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Brigham Minerals, Inc.ANNUAL
ANNUAL
REPORT
REPORT
2021
2021
Investing
for increased
gas supply
OUR PURPOSE
Cooper Energy’s purpose is to contribute to
Australia’s sustainable energy future by
commercialising gas, oil and other resources
for domestic markets.
We operate with an emphasis on care,
shareholder value and sustainability.
ACKNOWLEDGEMENT
Cooper Energy acknowledges the Kaurna people as the custodians of the Adelaide region of our head office,
the Whadjauk Noongar people on whose land our Perth office is based and the Eastern Marr people of the
western district of Victoria where our Athena Gas Plant is located.
COOPER ENERGY LIMITED
ABN 93 096 170 295
Cover image: Biodiverse Carbon Coorong Project, South Australia
Opposite: Ocean Monarch offshore drilling rig
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 “2021”, “FY21” and the “2021 financial year” refer to the 12 months
ended 30 June 2021 unless otherwise stated. Likewise references to 2020, FY20 or 2022, FY22 refer to the
12 months ending 30 June of that year.
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 on page 124.
WE ENERGISE THE
LIVES OF THOUSANDS
OF AUSTRALIANS
EVERY DAY BY FINDING,
DEVELOPING AND
COMMERCIALISING
GAS AND OIL
FROM THE CHAIRMAN
JOHN CONDE AO
This year we were presented again
with significant challenges to navigate.
Not being able to process and sell our Sole gas
at originally forecast levels had a flow-on effect to
revenue, cash flow and earnings, which in turn deferred
the progress of other growth projects. We are working
constructively with APA to secure certainty on the
long-term arrangements for processing Sole gas at
Orbost. We look forward to providing clarity on this
as the year progresses.
In the broader energy sector, there
is increasing pressure for companies
to demonstrate their commitment
to sustainability and emissions
management. There is increasing
activism and access to capital is
changing. However, Cooper Energy
is a leader in climate action within
the Australian oil and gas sector,
as discussed below.
We continue to manage the
ever-evolving COVID-19 pandemic.
Cooper Energy acted quickly in
2020 to implement procedures and
practices to manage the pandemic,
and we continue to monitor, react
and adapt as required. It is pleasing to note that
during the year we reported no cases of COVID-19
among our staff or contractors; we had no COVID-19
related interruptions to processing of gas and oil;
and our Athena Gas Plant Project progressed
on schedule. I extend my gratitude to all involved.
The challenges, and in particular the delays at Orbost,
have had an adverse impact on our share price.
We acknowledge the frustration this has caused our
shareholders and appreciate the ongoing loyalty shown
by many. In response to our results and share price
performance in the 2021 financial year, short-term
incentive payments were cut significantly across the
organisation and base salaries have again been held
constant for the Board and staff.
2
Key milestones
Your company maintained strict focus on delivering its
south-eastern Australia gas strategy. In doing so, we
achieved several key milestones which are transforming
Cooper Energy.
First, we took a major step in establishing ourselves
as a material and important supplier of gas to south-
eastern Australia with the initiation of our Sole Gas
Sales Agreements. With support from our customers
and the guiding principles of the Transition Agreement
with APA, we were able to
commence the sale of gas even
though the performance of the
Orbost Gas Processing Plant
remained volatile. The material
increase in revenue, earnings and
cash flow in the second half of
the 2021 financial year is expected
to continue in 2022 and beyond.
We met all customer gas
nominations on every day. At times
we had to draw on the back-up
arrangements we have in place.
This is a credit to our commercial
team and demonstrates the
value of our twin gas hub strategy and the customer
relationships that have been developed.
Secondly, we made great strides in establishing
ourselves as a mid-stream gas infrastructure operator,
with the upgrade of the Athena Gas Plant significantly
progressed. Once commissioned, the Athena Gas Plant
will give Cooper Energy control of processing our Otway
Basin gas and provide extra capacity for the next wave
of our gas developments.
Thirdly, we established ourselves as a leader in our
sector on climate action. We received independent
certification by Climate Active of our carbon neutral
position with respect to Scope 1, Scope 2 and
controllable Scope 3 emissions. This confirmed and
validated Cooper Energy as Australia’s first carbon
FROM THE CHAIRMAN
neutral gas and oil producer. While many companies
talk of future net zero aspirations, our actions to achieve
carbon neutrality put us many years, even decades,
ahead of our peers. As we grow, we plan to maintain
our net zero carbon status and will seek innovative
ways to harness the value from momentum in this area.
The Managing Director’s Report and the Financial
Report address our results and achievements in more
detail. The 2021 Sustainability Report, which was
published at the time of this Annual Report, addresses
our performance across health and safety, the
environment, climate actions, community involvement
and our relationships with stakeholders. I encourage
you to read these documents.
FY22 outlook
Prospectively, there are many reasons for optimism.
We are all feeling the impact that delays at Orbost and
related uncertainties have had on shareholder value,
cash flow generation and earnings.
APA will be undertaking additional work at Orbost,
which they plan to complete within the March 2022
quarter, with the objective of materially increasing
the gas processing rate. Extensive testing on solids
removal technology has provided us with confidence in
the work program to deliver further improvements
in plant performance. In addition, together with APA,
we continue our efforts to identify the root cause
of the underlying issues at Orbost.
The Athena Gas Plant will be commissioned this year,
providing us with control of processing Otway Basin
gas and capacity for future developments. The Otway
Phase 3 Development will be our first development to
utilise the additional capacity at Athena, resulting in new
gas supply for south-eastern Australia and a step-up in
cash flow and earnings for Cooper Energy. I expect this
will be followed by further gas discoveries in our Otway
Basin permits at a time when gas supply is very tight
and gas prices are increasing.
We will also continue our climate action program
and maintain our industry-leading carbon neutral
position. Net zero is one part of Cooper Energy’s
broader Sustainability strategy. For us, Sustainability
means offering a long-term value proposition for all
stakeholders while leaving our environment in a better
state than when we found it. Our assets, strategy
and values are aligned with this:
• We produce gas which we know will be required
for decades to come as the world transitions to
renewable energy.
• We have consolidated the company’s asset portfolio
around proven cost competitive gas provinces and
established infrastructure located close to the key
gas markets.
• We have an extensive resource position which
provides the foundation for increasing production and
cash flow over time.
• Most of our gas reserves are linked to long-term
contracts which offer stable prices and cash flow
through take-or-pay terms.
• We are proud of our environmental track record and
the relationships we have built with the communities
in which we operate.
• Our governance framework and Cooper Energy
values guide all decisions and actions.
Our actions to date demonstrate our commitment
to Sustainability.
Concluding remarks
Notwithstanding the challenging and disappointing year
for Cooper Energy and our shareholders, growth is
now underway and we are confident in our ability to
create ongoing sustainable growth in shareholder value
as we deliver our south-eastern Australia gas strategy.
Our twin gas hubs are established, gas supply is tight
and getting tighter, and the initiation of our Sole Gas
Sales Agreements has demonstrated the inherent value
of our Sole gas development.
3
COOPER ENERGY ANNUAL REPORT 2021 FROM THE CHAIRMAN
I record my thanks to my Board colleagues and to our
Company Secretary for their counsel and support. In
August, we welcomed Ms Giselle Collins to the Board,
subject to confirmation by shareholders at this year’s
annual general meeting. Ms Collins brings valuable
expertise to the Board and adds diversity of experience.
I also record my appreciation to our Managing Director,
David Maxwell, and his team for their leadership and
commitment to Cooper Energy.
I extend my gratitude to all stakeholders, and in
particular our lenders, customers, suppliers and
contractors for your ongoing support.
Lastly, thank you to you, our shareholders, for your
ongoing support. It was unquestionably a difficult year.
However, our foundation is set, our strategy is correct
and we are excited for the year ahead.
John Conde AO
Chairman
COOPER ENERGY
ACHIEVED MANY
KEY MILESTONES IN
2021 WHICH ARE
TRANSFORMING THE
COMPANY
4
Coorong Biodiversity Project
COOPER ENERGY ANNUAL REPORT 2021
5
MANAGING DIRECTOR'S
REPORT
DAVID MAXWELL
Our results for the 2021 financial year
were shaped by the ongoing delay in
commissioning the Orbost Gas Processing
Plant – owned and operated by APA.
This constrained Sole production, cash flow and
earnings, relative to our original expectations,
and impacted the progress of our growth projects.
This has weighed on our financial
results and the share price.
I acknowledge the frustration
this has caused and extend my
personal gratitude to you, my fellow
shareholders, for your ongoing
support through this period.
Despite the challenges, the 2021
financial year can be regarded as
transformational for Cooper Energy.
We delivered many key milestones
which are establishing the company
as a material and important supplier
of gas to south-eastern Australia
and setting the foundation for
sustainable growth in shareholder
value. The milestones include:
• Sole gas production: Commenced processing
through the Orbost Gas Processing Plant with
improving Orbost performance throughout the year
and further improvements expected in 2022.
• Sole Gas Sales Agreements: Commenced in
December and January and met every customer
nomination.
• Athena Gas Plant Project: Significant progress
in upgrading the Athena Gas Plant and establishing
Cooper Energy as a midstream gas infrastructure
operator.
• Financial performance: Record results and a step-
change in second-half performance following initiation
of the Sole Gas Sales Agreements.
6
• Health, safety and environment: Pleasing
performance against the backdrop of COVID-19.
• Carbon neutrality: Independent certification as
Australia’s first carbon neutral gas and oil producer.
• Gas market and strategy: Increasing gas supply
constraints in south-eastern Australia and increasing
gas prices playing out as expected.
These milestones were supported
by strong relationships with
our key stakeholders including
our customers, banks and the
communities in which we operate.
I discuss each of these topics
below.
2021 REVIEW
Sole and the Orbost Gas
Processing Plant
Cooper Energy delivered
the upstream Sole gas field
development on time and below
budget during the 2019 calendar year. Since then,
the Orbost Gas Processing Plant, which is owned and
operated by APA, has faced challenges due to foaming
and fouling within the plant’s Sulphur Recovery Unit.
Cooper Energy has been working constructively with
APA to increase processing rates and improve stability
while also focusing on identifying the root cause of
the foaming and fouling.
During the 2021 financial year, reconfiguration of the
plant’s Sulphur Recovery Unit was undertaken and
improvement in plant performance was seen during
the second half of the year. Processing rates improved
from 23 TJ/day on average in the first half to 35 TJ/day
on average in the second half. Subsequent to financial
year-end, stability had further improved with regular
cleaning of the absorbers and rates of approximately
40 TJ/day on average.
MANAGING DIRECTOR’S REPORT
APA will be undertaking further capital works at
Orbost which is scheduled to be complete during
the March 2022 quarter. Extensive testing on solids
removal technology during 2021 has provided us
with confidence that the planned activities can further
improve plant performance.
Your Board and Executive Leadership Team are acutely
aware of the impact Orbost performance has had on
Cooper Energy’s share price.
We are focused on providing
certainty regarding these longer-
term arrangements and are
working constructively with APA
to achieve such an outcome.
We look forward to providing
updates in due course.
Athena Gas Plant Project
In the Otway Basin, the Athena
Gas Plant is Cooper Energy’s
second gas processing hub.
Cooper Energy is the operator of
Athena and owns a 50% interest
alongside Mitsui E&P Australia.
During the 2021 financial year we made significant
progress in delivering the upgrade of the Athena Gas
Plant. Commissioning of the plant is now underway
and once complete will see Cooper Energy established
as a midstream gas infrastructure operator. This will
be a significant milestone for your company.
The Athena Gas Plant is a strategic asset ideally
located within the core south-eastern Australia gas
market, which is becoming increasingly short of
gas supply. It will be an integral asset within Cooper
Energy’s portfolio. It will allow for higher processing
rates from existing Otway Basin fields, operate at a
lower cost relative to current processing arrangements,
provide significant extra capacity for future
developments and discoveries, and enable enhanced
marketing of gas on a firm supply basis.
I thank all staff, contractors and stakeholders who
have contributed to the Athena Gas Plant upgrade.
The project has involved significant staff coordination,
training and delivery throughout its various stages.
Pleasingly, we have recorded no lost-time injuries
and the project stayed within schedule during the
2021 financial year despite the backdrop of COVID-19.
The learnings gained from the project to date are
COOPER ENERGY
IS BECOMING
A MATERIAL
AND IMPORTANT
SUPPLIER OF
GAS TO SOUTH-
EASTERN
AUSTRALIA
extensive and will prove
invaluable as we transition to a
gas processing plant operator
and continue to grow our
gas production.
Financial Performance
Our financial results in 2021
demonstrated a step-change
in revenue, mainly due to the
initiation of our Sole Gas Sales
Agreements in the middle of
the year. This was a significant
achievement for Cooper Energy,
particularly given the volatile
performance of the Orbost Gas
Processing Plant. With support from our customers,
third-party gas suppliers and APA, and guided by the
principles of the Transition Agreement, we delivered
over 8 petajoules of gas into our Sole Gas Sales
Agreements during the second half of the year. During
the peak winter gas demand months, we averaged
gas supply of 59 TJ/day, with Orbost shortfalls sourced
from our back-up supply arrangements.
The initiation of our Sole Gas Sales Agreements and
improving performance of the Orbost Gas Processing
Plant drove record production, sales volume and
revenue. Production was up 69% to 2.63 MMboe, sales
volume up 94% to 3.01 MMboe and revenue up 69% to
$132 million. We generated $50 million in cash margin
from our gas business in what was a challenging year.
7
COOPER ENERGY ANNUAL REPORT 2021 MANAGING DIRECTOR’S REPORT
The momentum from the second half of the year is
continuing into the 2022 financial year. The step-change
in earnings and cash flow which we have been referring
to for some time is now underway.
Our financial position remains sound and we are grateful
for the ongoing support of our lenders. Towards the
end of the financial year we adjusted our debt facility to
align it with current processing rates at Orbost of 40-45
TJ/day. The adjustments helped preserve liquidity so
we can continue advancing growth projects such as the
Otway Phase 3 Development.
Bank security for our debt facility is mainly in the Sole
2P Reserves and the long-term take or pay Gas Sales
Agreements. The adjustments demonstrate the strength
of this position and our lenders’ support for Cooper
Energy. At financial year-end, our cash reserves were
$91 million and drawn debt was $218 million.
Health, safety and the environment
We recorded pleasing health, safety and environmental
performance as we strive for continual improvement.
The ever-changing COVID-19 situation provided ongoing
challenges for us all. The policies and procedures
implemented by Cooper Energy early in the pandemic
have served us well and we continue to monitor, react
and adapt as required.
We had no reported cases of COVID-19 among our staff
and contractors. We also achieved no COVID-19 related
interruptions to our oil and gas processing, and the
Athena Gas Plant Project progressed to schedule
as noted above.
We reported no lost-time injuries. We did have two
minor safety incidents which resulted in an increase to
our total recordable injury frequency rate. The incidents
were a hamstring strain and a cut on the nose. For both
incidents, the individuals returned to work the following
day. We again had no reportable environmental
incidents at our operated sites.
The 2021 Sustainability Report, which was published
at the time of this Annual Report, addresses our
performance across health and safety, the environment,
climate actions, community involvement and our
relationships with stakeholders. I encourage you to read
this report.
Carbon neutral certification
Cooper Energy’s accelerated push to achieve net zero
carbon emissions was a great accomplishment for
the organisation. We announced in October 2020 our
commitment to net zero carbon emissions, that is Scope
1, Scope 2 and controllable Scope 3 emissions. We
achieved this through partnering with Greening Australia
in the Coorong Biodiversity Project.
Towards the end of the financial year we received
independent certification from Climate Active as
Australia’s first carbon-neutral gas producer. This is a
fantastic accomplishment for Cooper Energy.
The feedback has been overwhelmingly supportive.
Our staff appreciate it and are proud to be working for
a net zero gas producer. Our lenders acknowledge it
and we expect to benefit from better access to
debt capital markets in the future. Our institutional
shareholders like it, particularly those who may
otherwise be restricted from investing in Cooper Energy.
Our broader stakeholders and communities like it as it
reinforces our commitment to working sustainably.
We are progressing other carbon reduction initiatives
which are timed to align with our gas production growth.
We have several cost-effective opportunities under
review and will have more to say on these in due course.
Our focus on maintaining carbon neutrality is one
part of our broader objectives in the area of
Environment, Sustainability and Governance (ESG).
Our objectives aim to create a long-term sustainable
investment proposition for our investors and a long-term
valuable contributor to our broader stakeholders
and communities.
Gas market and strategy
While we work with APA to rectify the issues at the
Orbost Gas Processing Plant and progress our other
growth projects, increasing gas supply shortages in the
south-eastern Australia gas market continue to play
out as we expected.
The gas demand-supply fundamentals remain
challenged and skewed towards increasing gas supply
shortfalls. It is a fact that gas will be needed for decades
to come, and that gas will support our transition to
renewable energy. However, industry and regulators
continue to see tight gas supply for south-eastern
8
MANAGING DIRECTOR’S REPORT
Australia, with a supply shortfall of approximately 60
petajoules expected by 2025. This equates to roughly
four Sole projects at current Orbost processing rates.
The shortfall is driven by several factors, including
declining production from existing fields as reservoirs
deplete, increasing costs and regulatory burden
associated with new developments, and various drilling
moratoriums which have hampered new supply. To have
a positive impact on the supply shortfall come 2025,
new gas projects need to be at the Final Investment
Decision stage now or very soon.
Pricing fundamentals also remain sound for Cooper
Energy. LNG and spot gas prices increased over the
course of the year which supports our view that the
long-term contracted gas price range will be $8-$11/GJ.
The gas supply challenges will persist for south-eastern
Australia. Thankfully, our twin gas hub strategy and
existing asset portfolio provide a clear pathway for
discovering and developing gas reserves over time.
Our Otway and Gippsland basin permits are in cost
competitive gas producing regions, include multiple
attractive exploration prospects and are connected to
customers via existing pipeline infrastructure. These are
strategically located assets that will support customers
while the gas supply shortfall grows.
Our opportunity pipeline includes growing production
from existing producing assets, developing resources
over the near-term, and exploring for new discoveries.
The Athena Gas Plant will provide extra processing
capacity, allowing us to develop gas through our own
plant at attractive margins.
It is key that we have effective energy policy and
regulations which have regard to the needs of society
whilst supporting the ongoing development of the
gas industry. Our industry is vital to support the
development and reliable supply of renewable energies
and numerous everyday products.
Athena Gas Plant
9
COOPER ENERGY ANNUAL REPORT 2021 MANAGING DIRECTOR’S REPORT
2022 OUTLOOK
Cooper Energy’s purpose is to contribute to Australia’s
sustainable energy future by commercialising gas,
oil and other resources for domestic markets. We
operate with an emphasis on care, shareholder value
and sustainability. To achieve this purpose, our
strategy involves:
• establishing a portfolio of low cost, long-term gas and
oil production assets;
• growing through a combination of exploration,
development and acquisition;
• participating in APA’s delivery of the next phase of
capital works at Orbost which aim to further improve
plant stability and performance;
• commissioning the Athena Gas Plant to deliver
benefits including higher processing rates, lower
operating costs and improved gas marketing
capability;
• preparing for a Final Investment Decision for the next
phase of development in the offshore Otway Basin;
and
• building future resilience by prioritising Environment,
• progressing other exploration, appraisal and
Sustainability and Governance and investing in
sustainable energy projects;
development activities within Cooper Energy’s existing
portfolio of growth opportunities.
• leveraging and developing our people, stakeholder
relationships and capabilities where we operate; and
• balancing risk by sharing opportunities, partnering and
achieving good commercial outcomes.
Specific activities planned for the FY22 financial
year include:
• finalising commercial arrangements with APA for the
long-term processing of Sole gas through the Orbost
Gas Processing Plant;
I record my appreciation for the loyal support of
our shareholders, lenders and customers, and the
committed effort of our employees and contractors
during the year. I also acknowledge the valuable
guidance and support provided by the Board during
what was a challenging year.
David Maxwell
Managing Director
10
COOPER ENERGY ANNUAL REPORT 2021
Orbost Gas Processing Plant
Ocean Monarch offshore drilling rig
COOPER ENERGY ANNUAL REPORT 2021
11
OUR VALUES
Cooper Energy is a values-driven
business with actions guided at all
times by our seven core values.
12
CARE
Prioritising safety, health, the environment
and community.
INTEGRITY
Striving to be consistent, staying true to our
values and accountable for our actions.
FAIRNESS AND RESPECT
Valuing diversity and difference, acting without
prejudice and communicating with courtesy.
TRANSPARENCY
Being honest, addressing problems and
being clear with our communications.
COLLABORATION
Sharing ideas and knowledge, encouraging
cooperation, listening to our stakeholders and
building long-term relationships.
AWARENESS
Taking account of all identified key issues in our
decisions and considering future impacts.
COMMITMENT
Staying focused on the core objectives, making
pragmatic, quality technical and commercial
decisions and being decisive with the courage
of our convictions.
OUR BUSINESS
We generate revenue from the discovery,
commercialisation and sale of gas to south-
eastern Australia and from oil production
and development in the Cooper Basin.
0.16
0.77
FY21 Production
2.63 MMboe
1.70
Gippsland Basin gas
Otway Basin gas and gas liquids
Cooper Basin oil
1.1
8.9
2P Proved and
Probable Reserves
47.1 MMboe
at 30 June 2021
Gippsland Basin
Otway Basin
Cooper Basin
OTHER KEY STATISTICS
at 30 June 2021
Market capitalisation
$424.1 million
Net debt
Issued shares
Shareholders
$126.7 million
1,631 million
9,355
Employees and contractors
105.3 full time equivalent
We aim to deliver sustainable growth in shareholder
value by:
• establishing a portfolio of low-cost, long-term gas
and oil production assets;
• growing through a combination of development,
exploration and acquisition;
• building future resilience by prioritising Environment,
Sustainability and Governance and investing in
sustainable energy projects;
• leveraging and developing our people, stakeholder
relationships and capabilities; and
• balancing risk by sharing opportunities, partnering
and achieving good commercial outcomes.
37.1
0.5
8.0
2C Contingent
Resources
33.9 MMboe
at 30 June 2021
25.4
Gippsland Basin
Otway Basin
Cooper Basin
13
COOPER ENERGY ANNUAL REPORT 2021 OUR OPERATIONS
2
PERTH
3
ADELAIDE
1
MELBOURNE
6
4
5
ADELAIDE
• Corporate head office
PERTH
• Projects and offshore drilling office
COOPER BASIN
• Western Flank oil production, development
and exploration
• 25% Cooper Energy interest
ATHENA GAS PLANT
• Processing hub for offshore Otway Basin gas
• Commissioning in FY22
• 50% Cooper Energy interest
1
2
3
4
ONSHORE OTWAY BASIN
• Dombey gas discovery
• Gas exploration and development prospects
• 30% Cooper Energy interest (South Australia)
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 3 Development
• 50% Cooper Energy interest
GIPPSLAND BASIN
• Sole gas field
• Manta gas and gas liquids resource and
multiple gas exploration prospects
• 100% Cooper Energy interest
4
5
6
14
ENVIRONMENT, SUSTAINABILITY
AND GOVERNANCE
INDUSTRY-LEADING NET ZERO DECARBONISATION POSITION
• Net Zero achieved for the second consecutive year
• 100% Scope 1, Scope 2 and controllable Scope 31 offset
• 4,338 tonnes of CO2 offset
• Commitment to continue this initiative for the foreseeable future
• 2020 South Australian Premier’s Award for Environment for Net Zero initiative
• Climate Active Carbon Neutral Organisation certification achieved
HEALTH, SAFETY AND ENVIRONMENT
• 0 lost-time injuries
• 0 reportable environmental incidents
• 0 COVID-19 cases; management plans in place at all sites
• 2 minor contractor medical treatment incidents; both returned to work the following day
GENDER DIVERSITY
• Ahead of industry benchmarks
• 38% female representation on the Board of Directors2
• 28% overall company female representation
LOCAL CONTENT
• >$60 million in local purchases
• >375 local suppliers
Full details are contained in the Cooper Energy 2021 Sustainability Report,
published concurrently with this Annual Report.
1. Controllable Scope 3 emissions comprise carbon embedded in concrete and steel, and employee travel.
Customer emissions from transportation of gas purchased and ultimate combustion are not included.
2. Post appointment of Giselle Collins on 19 August 2021, subject to confirmation by shareholders at this
year’s annual general meeting.
15
COOPER ENERGY ANNUAL REPORT 2021 KEY RESULTS
FINANCIAL
• Record sales revenue, up 69% to $131.7 million from initiation of the Sole Gas Sales Agreements
• Underlying net loss after tax of $25.9 million, impacted by delayed commissioning of the Orbost Gas
Processing Plant
• Debt facility adjusted with ongoing support from lenders
• Higher depreciation and amortisation due to increased Sole production
• General administration expense down 16% to $12.7 million
Sales revenue
$ million
Statutory net profit / (loss) after tax
$ million
Underlying net profit / (loss) after tax
$ million
131.7
27.0
13.3
9.8
(12.3)
(12.1)
(30.0)
(8.7)
(6.6)
75.5
78.1
67.5
39.1
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
(86.0)
(25.9)
Operating cash flow
$ million
Net cash / (debt)
$ million
48.1
147.4
111.0
Total equity
$ million
443.9
433.7
351.1
325.8
285.0
22.2
20.5
4.1
8.1
(53.9)
(97.8)
(126.7)
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
16
KEY RESULTS
OPERATIONS AND RESERVES
• No lost-time injuries and no reported COVID-19 cases
• Two minor contractor incidents; both individuals returned to work the following day
• Record production, up 69% to 2.63 MMboe
• Athena Gas Plant Project significantly progressed
• Climate Active carbon neutral certification achieved
Safety
Total recordable injury frequency rate
Production
MMboe
Proved and Probable Reserves
MMboe
6.9
2.63
52.4
52.7
49.9
47.1
3.5
1.49
1.31
1.56
0.96
11.7
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
EQUITY
Share price
cents per share at 30 June
Basic earnings per share
cents per share at 30 June
Market capitalisation
$ million at 30 June
54.0
1.8
(0.7)
873
38.0
38.5
37.5
(1.8)
(1.8)
616
608
26.0
433
424
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
(5.3)
17
COOPER ENERGY ANNUAL REPORT 2021 KEY RESULTS
GAS AND OIL REVENUE
• Twin gas hub strategy delivering step-change in sales volume and revenue
• Record total sales volume, up 94% to 3.01 MMboe
• Gas revenue up 88% to $119.5 million from initiation of the Sole Gas Sales Agreements
GAS
Total sales volume (PJ)
Total revenue ($ million)
2P Proved and Probable Reserves1 (PJ)
Average realised price ($/GJ)
OIL AND CONDENSATE
Total sales volume (kbbl)
Total revenue ($ million)
2P Proved and Probable Reserves1 (MMbbl)
Average realised price ($/bbl)
1. As announced on 23 August 2021.
FY21
17.4
119.4
281.3
6.86
FY21
153.8
12.3
1.1
79.0
Darwin
FY20
8.3
63.6
295.3
7.66
FY20
186.0
14.5
1.6
77.0
Port Hedland
Dampier
Carnarvon
Cooper Basin
Perth
Gladstone
Brisbane
Adelaide
Sydney
Otway Basin
Melbourne
Gippsland Basin
Hobart
18
KEY RESULTS
CAPITAL EXPENDITURE
• Lower capital expenditure due to completion of the Sole gas development
• Expenditure predominantly related to upgrade of the Athena Gas Plant
BY ACTIVITY ($ million)
Exploration and appraisal
Development
Total
BY BASIN ($ million)
Gippsland Basin
Otway Basin
Cooper Basin
Other
Total
FY21
2.2
30.1
32.3
FY21
0.4
27.3
1.7
2.9
32.3
FY20
41.6
35.1
76.7
FY20
17.7
35.5
10.4
13.1
76.7
Athena Gas Plant team
19
COOPER ENERGY ANNUAL REPORT 2021 RESERVES AND CONTINGENT RESOURCES
RESERVES
Cooper Energy’s 2P oil and gas Reserves at 30 June 2021 are assessed to be 47.1 MMboe (30 June 2020:
49.9 MMboe), as summarised in the following tables and notes and described in more detail in the ASX
announcement of 23 August 2021.
RESERVES AT 30 JUNE 2021
1P (Proved)
2P (Proved and Probable)
3P (Proved, Probable and Possible)
Developed Undeveloped
Total Developed Undeveloped Total Developed Undeveloped
Total
Sales gas
PJ
Oil &
Condensate
MMbbl
171
0.5
Total1
MMboe
28.4
30
0.0
4.9
201
0.5
238
1.1
33.4
40.0
43
0.1
7.1
281
1.1
323
1.5
47.1
54.4
56
0.1
9.3
380
1.6
63.7
1. Totals throughout these tables may not reflect arithmetic addition due to rounding; estimates exclude Cooper Energy’s share of future fuel,
flare and vent consumption and are net to Cooper Energy.
Key factors contributing to the change in Reserves since 30 June 2020 include:
• production of 2.6 MMboe in FY21;
• upward revisions in the offshore Otway Basin due to revised subsurface interpretation of the Henry gas field and production
performance of the Casino, Henry and Netherby gas fields; and
• downward revisions in PEL 92 due to revised operator decline profiles, execution of development projects during FY21 and
re-classification of two projects from Undeveloped Reserves to Contingent Resources.
YEAR-ON-YEAR MOVEMENT IN 2P RESERVES
Proved and Probable 2P Reserves (MMboe)
Cooper Basin
Otway Basin
Gippsland Basin
Reserves at 30 June 2020
FY21 Production
Revisions
Reserves at 30 June 2021
1.6
(0.2)
(0.3)
1.1
9.5
(0.8)
0.2
8.9
38.8
(1.7)
(0.1)
37.1
Total
49.9
(2.6)
(0.1)
47.1
YEAR-ON-YEAR MOVEMENT IN 1P, 2P AND 3P RESERVES
Proved (1P)
Proved & Probable (2P)
Proved, Probable & Possible (3P)
MMboe
MMboe
MMboe
Reserves
30 June 2020
Production
Revisions
FY21
FY21
Reserves
30 June 2021
35.5
(2.6)
0.5
33.4
49.9
(2.6)
(0.1)
47.1
66.6
(2.6)
(0.3)
63.7
20
RESERVES AND CONTINGENT RESOURCES
RESERVES BY BASIN AND PRODUCT AT 30 JUNE 2021
Reserves at 30 June 2021 Developed and Undeveloped
Proved (1P)
Proved and Probable (2P)
Proved, Probable and Possible (3P)
Cooper Otway Gippsland Total 1 Cooper Otway Gippsland Total 1 Cooper Otway Gippsland Total 1
Developed
Sales Gas
PJ
–
Oil & Condensate MMbbl
0.5
Developed total
MMboe
0.5
6.7
0.0
1.1
Undeveloped
Sales Gas
PJ
–
29.9
Oil & Condensate MMbbl
Undeveloped total MMboe
Total
MMboe
0.0
0.0
0.5
0.0
4.9
6.0
164.3
171.1
–
11.2
226.8
238.0
–
14.1
309.3
323.4
–
0.5
26.9
28.4
1.1
1.1
0.0
1.8
–
1.1
37.1
40.0
1.5
1.5
0.0
2.3
–
50.5
29.9
–
43.2
43.2
–
56.5
–
–
–
0.0
4.9
0.0
0.0
1.1
0.0
7.1
8.9
–
–
–
0.1
7.1
0.0
9.3
0.1
0.1
1.6
26.9
33.4
37.1
47.1
11.6
50.5
63.7
1.5
54.4
56.5
0.1
9.3
–
–
–
CONTINGENT RESOURCES
Cooper Energy’s 2C oil and gas Contingent Resources at 30 June 2021 are assessed to be 33.9 MMboe (30 June 2020:
34.9 MMboe). The decrease is primarily due to revisions to PEL 92 oil projects and conversion of gas 2C Contingent
Resources to 2P Reserves.
CONTINGENT RESOURCES AT 30 JUNE 2021
1C
2C
3C
Gas
PJ
83.1
32.3
–
115.3
Oil & Cond.
MMbbl
Total
MMboe
2.2
0.0
0.3
2.5
15.8
5.3
0.3
21.4
Gas
PJ
134.9
48.6
–
183.5
Gippsland Basin
Otway Basin
Cooper Basin
Total
Oil & Cond.
MMbbl
Total
MMboe
3.4
0.1
0.5
4.0
25.4
8.0
0.5
Gas
PJ
212.3
63.2
–
Oil & Cond.
MMbbl
Total
MMboe
5.4
0.1
0.9
6.4
40.1
10.4
0.9
51.4
33.9
275.5
YEAR-ON-YEAR MOVEMENT IN CONTINGENT RESOURCES
MMboe
Contingent Resources at 30 June 2020
Revisions
Contingent Resources at 30 June 2021
1C
21.6
(0.2)
21.4
2C
34.9
(0.9)
33.9
3C
52.0
(0.6)
51.4
21
COOPER ENERGY ANNUAL REPORT 2021 RESERVES AND CONTINGENT RESOURCES
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 Annual Report are
as at 30 June 2021.
All Reserves and Contingent Resources figures in
this document are net to Cooper Energy unless
otherwise stated.
Cooper Energy has completed its own estimation of
Reserves and Contingent Resources for its operated
Otway and Gippsland Basin assets. Elsewhere,
Reserves and Contingent Resources estimation is
based on assessment and independent views of
information provided by the permit operators (Beach
Energy Limited for PEL 92 and the Worrior field).
Reference points for Cooper Energy’s petroleum
Reserves and Contingent Resources and production
are defined 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 and probabilistic methods.
The Reserves and Contingent Resources estimate
methodologies incorporate a range of uncertainties
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.
Totals may not exactly reflect arithmetic addition due
to rounding.
The conversion factor of 1 PJ = 0.163 MMboe has been
used to convert from sales gas (PJ) to oil equivalent
(MMboe).
22
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 and the
arithmetic summation of the Worrior field Reserves.
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
Contingent Resources in the Gippsland, Otway and
Cooper basins.
Qualified petroleum Reserves and
Contingent 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 by Mr Andrew
Thomas who is a full-time employee of Cooper
Energy Limited holding the position of General
Manager – Exploration & Subsurface. 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.
REVIEW OF OPERATIONS
SAFETY
Detailed discussion of Cooper Energy’s safety performance is provided in the 2021 Sustainability Report. The 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
1. Per million hours worked
FY21
289,071
2
–
–
6.91
3.19
FY20
283,672
1
1
3.53
3.53
5.27
2. TRIFR is recordable incidents (Medical Treatment Injuries + Restricted Work/Transfer Case + Lost-Time Injuries + Fatalities)
per million hours worked. Calculated on a rolling 12-month basis
3. Industry TRIFR is the NOPSEMA benchmark for offshore Australian operations; data is for the last full calendar year;
published at www.nopsema.gov.au
PRODUCTION
Cooper Energy recorded record oil and gas production of 2.63 MMboe due mainly to increasing gas production
from the Sole field in the Gippsland Basin.
PRODUCTION
Gippsland Basin
Otway Basin
Cooper Basin
Total
FY21
Oil and
condensate
(kbbl)
–
1.8
156.9
158.7
Total
(MMboe)
1.70
0.77
0.16
2.63
Gas
(PJ)
10.4
4.7
–
15.1
Production by region
MMboe
1.70
0.77
0.16
FY21
1.22
1.07
0.34
1.02
0.27
0.24
0.19
0.68
0.25
0.25
FY17
FY18
FY19
FY20
FY20
Oil and
condensate
(kbbl)
Total
(MMboe)
–
3.5
193.0
196.5
0.34
1.03
0.19
1.56
Gas
(PJ)
2.1
6.2
–
8.3
Gippsland Basin
Otway Basin
Cooper Basin
South Sumatra, Indonesia
23
COOPER ENERGY ANNUAL REPORT 2021 REVIEW OF OPERATIONS
GIPPSLAND BASIN
Cooper Energy is the Operator and 100% interest
holder for all of its Gippsland Basin interests.
As at 30 June 2021, these interests comprised:
• installation of spray nozzles in the absorbers to
suppress foaming and reduce fouling; and
• installation of solids removal technology to prevent
• VIC/L32, which contains the Sole gas field;
fouling within the absorbers.
• VIC/RL13, VIC/RL14 and VIC/RL15, which contain
the Manta 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 and VIC/P75.
Development: Sole Gas Project and OGPP
The Sole Gas Project involves development of the
Sole gas field by Cooper Energy and upgrading of the
OGPP by APA to process Sole gas.
The offshore project was completed by Cooper Energy
during the 2019 calendar year within schedule, below
budget, with zero lost-time injuries and with zero
reportable environmental incidents. Total capital cost
for the offshore project was $335 million compared with
a budget of $355 million.
Commissioning of the OGPP by APA is continuing.
The plant’s performance has been impaired by foaming
and fouling in the sulphur recovery unit’s two absorbers,
which has constrained processing rates and required
regular maintenance and cleaning. During Q2 FY21,
reconfiguration works were undertaken by APA to enable
operation of the absorbers independently, in parallel
or in series. These works provided greater operational
flexibility and the ability to conduct cleaning of absorbers
while minimising interruption to production.
Subsequent to financial year-end, Cooper Energy
provided approval to APA for further capital works
at OGPP to be undertaken during FY22. The work
program is designed to significantly improve plant
performance and includes:
The analysis to determine the underlying root cause
of foaming and fouling at OGPP is continuing. In Q4
FY21, APA and Cooper Energy engaged a specialist
surfactant chemist to peer review the testing results
and analysis previously undertaken. The surfactant
chemist’s scope of work is being overseen by a
technical committee comprising APA and Cooper
Energy representatives.
Exploration
The exploration focus in the Gippsland Basin has been
on VIC/P75 in the Basin’s central area. The permit
is surrounded by major fields, including the Marlin,
Snapper and Barracouta gas fields to the north and the
Kingfish and Fortescue oil fields to the south and east.
Interpretation and depth conversion of the reprocessed
3D seismic data in VIC/P75 was completed and a
prospect called Spineback was identified. Resource
and risk assessment of Spineback is underway.
In VIC/RLs 13, 14 and 15, the prospectivity under
existing discoveries is being reviewed based on
an improved understanding of depth conversion in the
Gippsland Basin from work in VIC/P75. In addition
to the Manta Deep prospect, which could be drilled
by deepening a future Manta-3 appraisal well to
approximately 4,500 metres, investigations are
ongoing on similar prospectivity below the discovered
Gummy field.
A suspension and extension of VIC/P72 was received
from NOPTA, with the permit’s primary term now
expiring in May 2023. VIC/P72 adjoins VIC/RL16,
which holds the Patricia-Baleen gas field and
associated subsea production infrastructure connected
to the OGPP. VIC/P72 is close to several Esso-
operated oil and gas fields including Remora, Snapper,
Sunfish and Sweetlips, and the SGH Energy-operated
Longtom gas field. Prospects identified in VIC/P72
are analogues to offset fields.
24
REVIEW OF OPERATIONS
BMG abandonment
The abandonment project in the BMG fields involves
decommissioning seven wells and associated subsea
infrastructure in the Gippsland Basin. The BMG
permits contain the proven Manta gas field and the
Manta Deep prospect.
The BMG abandonment project entered the
FEED stage, with activities focused on selecting
optimal methodologies and technologies for safe
and cost-effective delivery of the decommissioning
objectives. Regulatory documentation, including
the Well Operations Management Plan, was submitted
to the regulator, NOPSEMA, and the review process
Melbourne
VICTORIA
Orbost
E A STERN GAS PIPEL I N E
Orbost Gas Processing Plant
Lakes Entrance
is underway. Details of the scope of works and cost
estimates will be announced after all details have
been received and the required assurance review
is completed.
In consultation with industry, Cooper Energy is
considering NOPSEMA’s Decommissioning
Compliance Strategy, which was released in April
2021. Cooper Energy continues to liaise closely with
the regulator and other stakeholders to ensure
ongoing compliance with the regulatory requirements.
To Sydney
To Sydney
Plan area
TA
VIC/P72 (100%)
Sweetlips
Patricia-Baleen
Moby
VIC/RL16 (100%)
Longtom
Moonfish
Snapper
Marlin
Barracouta
VIC/P75 (100%)
Veilfin
Luderick
Bream
0
20
kilometres
Gippsland_136
Gippsland Basin
Sunfish
Tuna
Judith
VIC/L32 (100%)
Sole
Batfish
Angelfish
Flounder
Fortescue
Kipper
Grunter
Scallop
Chimaera
Manta
VIC/RL15 (100%)
Basker
Gummy
VIC/RL13 (100%)
VIC/RL14 (100%)
Mackerel
Blackback
Kingfish
Cooper Energy
tenement
Gas field
Oil field
Prospect
Gas pipeline
Oil pipeline
25
COOPER ENERGY ANNUAL REPORT 2021 REVIEW OF OPERATIONS
OTWAY BASIN (OFFSHORE)
The company’s interests in the offshore Otway Basin
as at 30 June 2021 comprised:
• a 50% interest in and Operatorship of production
licences VIC/L24 and VIC/L30 containing the
producing Casino, Henry and Netherby gas fields,
with the remaining 50% interest held by Mitsui E&P
Australia and its associated entities (“Mitsui”);
• a 50% interest in and Operatorship of production
licences VIC/L33 and VIC/L34 containing part of
the Black Watch and Martha gas fields, with the
remaining 50% interest in these production licences
held by Mitsui;
• a 50% interest in and Operatorship of exploration
permit VIC/P44 containing the undeveloped Annie
gas discovery, with the remaining 50% interest held
by Mitsui;
• a 100% interest in and Operatorship of exploration
permit VIC/P76;
• a 50% interest in and Operatorship of the Athena Gas
Plant (onshore Victoria) which is jointly owned with
Mitsui and is being recommissioned to process gas
from Casino, Henry and Netherby and other Otway
Basin discoveries; and
• a 10% non-operated interest in production licence
VIC/L22 which holds the shut-in Minerva gas field,
with BHP the Operator and 90% interest holder.
Exploration
Reprocessing of 3D seismic data covering VIC/P76,
VIC/P44, VIC/L24, VIC/L30, VIC/L33 and VIC/L34
commenced, with completion targeted for early FY22.
Geoscience studies progressed for the Elanora, Juliet,
Nestor and Pecten East prospects, including review
of the successful Artisan-1 exploration well of Beach
Energy Limited (“Beach”) in neighbouring VIC/P43. The
studies have increased Cooper Energy’s confidence in
the size and prospectivity of Juliet and Nestor. Wells
targeting these prospects will be assessed for inclusion
in future drilling campaigns. All prospects show strong
seismic amplitude support for the presence of gas and
are close to production infrastructure.
26
Suspension, extension and variations for VIC/P44
and VIC/P76 were received from NOPTA, with the
permits’ primary terms now expiring in May 2023 and
September 2024, respectively.
Development: Otway Phase 3
Development Project (“OP3D”)
OP3D involves development of the Annie gas discovery
and Henry gas field to produce more than 120 PJ of
gas through the Athena Gas Plant. OP3D is currently in
the Select Phase with planning for development drilling
underway. The timing for a FID will be made having
regard to optimisation for market timing and funding.
Cooper Energy received Declaration as a Location
approvals for the Annie discovery in VIC/P44 and
VIC/P76 from NOPTA. These regulatory approvals
acknowledge the location of the Annie discovery and
reserve the permits for conversion to future retention or
production licenses.
Development: Athena Gas Plant Project
The Athena Gas Plant Project commenced in Q1 FY21
following COVID-19 related delays during the prior
financial year. The project involves commissioning
the Athena Gas Plant to process gas and liquids from
the Casino, Henry and Netherby fields and from
future developments.
The upgrade is on schedule and on budget, with the
work program approximately 80% complete at financial
year-end. Mechanical completion has been achieved
and preparations commenced for commissioning and
start-up readiness. Work also commenced on the
pipeline cutover which when complete will direct gas from
the Casino, Henry and Netherby fields to the Minerva
Pipeline which connects to the Athena Gas Plant.
First commissioning gas through the plant is expected
in Q1 FY22 and cutover of processing from the Iona
Gas Plant to the Athena Gas Plant is expected in
Q2 FY22 following the peak winter demand period.
Once operational, the Athena Gas Plant will be
an integral asset within Cooper Energy’s gas portfolio.
REVIEW OF OPERATIONS
Expected benefits from re-commissioning the
plant include:
• the ability to produce gas from the Casino, Henry
and Netherby fields at a higher rate due to the plant’s
lower inlet pressure relative to the Iona Gas Plant;
• lower operating costs relative to current tariffs paid
for gas processed through the Iona Gas Plant;
• additional gas processing capacity (total plant
capacity of ~150 TJ/day) to support Otway Basin gas
developments such as OP3D and future discoveries;
and
• enhanced gas production and marketing flexibility,
with the ability to offer firm gas supply and manage
Sole customer requirements using Cooper Energy’s
Otway Basin gas if required.
Adelaide
Warrnambool
PEP 168 (50%)
Cooper Energy tenement
Gas field
Gas pipeline
Gas well
Prospect
Melbourne
VICTORIA
VIC/L34 (50%)
VIC/L33 (50%)
VIC/P44 (50%)
Martha
VIC/L30 (50%)
Netherby
Henry
Black Watch
Iona Gas Plant
Athena Gas Processing Plant
VIC/P44 (50%)
VIC/L22 (10%)
Annie
Minerva
Casino
VIC/P44 (50%)
VIC/P76 (100%)
VIC/L24 (50%)
Plan area
TA
0
10
kilometres
Otway 176
Otway Basin
27
COOPER ENERGY ANNUAL REPORT 2021 REVIEW OF OPERATIONS
OTWAY BASIN (ONSHORE)
COOPER BASIN
The company’s interests in the onshore Otway Basin
include licences in South Australia and permits in
Victoria. Activities in the latter were suspended
pursuant to a Victorian State Government moratorium
on onshore gas exploration, which was imposed
in 2017. That moratorium has been overturned by
the Petroleum Legislation Amendment Act 2020
(Vic) with effect from 1 July 2021. The company’s
interests in the onshore Otway Basin as at 30 June
2021 comprised:
• a 30% interest in PEL 494, PRL 32 and PEL 680 in
South Australia with the remaining interests held by
the Operator, Beach;
• a 50% interest in PEP 168 in Victoria with the
remaining interest held by the Operator, Beach; and
• a 75% interest in PEP 171 in Victoria, which may
reduce to 50% on fulfilment of farm-in arrangements
executed with joint venture partner and Operator
Vintage Energy Limited.
Exploration
Preparation for the Dombey 3D seismic acquisition
in PEL 494 progressed during the financial year. The
seismic acquisition is expected to be conducted in
FY22 and will cover the Dombey gas discovery in the
Penola Trough.
The South Australian Department for Energy and
Mining granted PEL 680 to Beach and Cooper Energy
during the financial year. The five-year work program
consists of geological and geophysical studies and
reprocessing of 2,700 km of 2D seismic.
Cooper Energy withdrew from the PEP 150 joint
venture during the financial year.The Victorian
Department of Jobs, Precincts and Regions is
reviewing the revised work programs for PEP 168 and
PEP 171, following the lifting of the onshore Victorian
exploration moratorium.
28
The company’s interests in the Cooper Basin as
at 30 June 2021 comprised:
• a 25% interest in PRLs 85-104 (the “PEL 92 Joint
Venture”) with the remaining interests held by the
Operator, Beach;
• a 30% interest in PRLs 231-233 (the “PEL 93 Joint
Venture”), with the remaining interests held by the
Operator, Beach;
• a 20% interest in PRL 237, with the remaining
interests held by Metgasco Limited and the
Operator, Beach;
• a 19.165% interest in PRLs 207-209 (formerly PEL
100), with the remaining interests held by Santos
QNT Pty Limited and the Operator, Beach; and
• a 20% interest in PRLs 183-190 (formerly
PEL 110), with the remaining interests held by the
Operator, Beach.
Sale of oil interests to Bass Oil Limited
As announced by Bass Oil Limited (ASX: BAS, “Bass”)
on 12 July 2021, agreement was reached for Bass to
acquire Cooper Energy’s interest in the Worrior oil field
(PPL 207) and certain other Cooper Basin exploration
permits for $0.65 million. The transaction includes the
company’s 30% interest in PRLs 231-233, the 20%
interest in PRLs 183-190 and PRL 237, and 19.165%
interest in PRLs 207-209. The transaction is subject to
various conditions precedent, including a Bass capital
raising and regulatory approvals.
The sale of these oil interests demonstrates Cooper
Energy’s ongoing focus on portfolio optimisation and
divesting of assets considered non-core. This focus
will continue, and particularly in the context of Cooper
Energy’s primary focus on commercialising gas
resources for south-eastern Australia.
Development
One oil development well was drilled during the
financial year, being the Callawonga-13 horizontal oil
development well in PEL 92. The well was drilled to
a total depth of 3,226 metres with a lateral section of
1,106 metres in the primary target McKinlay Member.
The preliminary assessment of results indicated a net
pay section of 605 metres across the lateral section.
Installation of flowlines and artificial lift was completed
and Callawonga-13 commenced production in May.
REVIEW OF OPERATIONS
PEL 494 (30%)
SOUTH AUSTRALIA
Beachport
PEL 680 (30%)
Millicent
Dombey-1
PRL 32 (30%)
Coonawarra
Coonawon
a
C
Coona
nawarraaa
Penola
VICTORIA
PEP 171 (75%)
Strathdownie
Mount Gambier
M
Cooper Energy tenement
0
10
20
kilometres
Gas field
Gas pipeline
Gas well
Prospect
Nelson
SOUTH AUSTRALIA
PRLs 183-190 (20%)
Plan area
Otway 177
Otway 177
Onshore Otway Basin
Plan area
TA
TA
Cooper Energy
tenement
Gas field
Oil field
Gas pipeline
Oil pipeline
PRLs 207-209 (19.165%)
edge
e r m ia n
P
A
R
R
A
W
A
H
P A T C
O U G H
R
T
R I
R
E
M
A
A P P
N
R O U G H
T
Rincon
North
Rincon
PRLs 85 to 104 (25%) (PEL 92)
Callawonga
Elliston
Parsons
Perlubie
Germein
Windmill
Sellicks
Christies
Silver Sands
Butlers
Lycium Hub
PRL 231 (30%)
MOOMBA
PRL 232 (30%)
PRL 233 (30%)
Worrior
PPL 207 (30%)
PRL 237 (20%)
0
20
40
kilometres
Cooper Basin
Cooper 95
29
COOPER ENERGY ANNUAL REPORT 2021 PORTFOLIO
COOPER ENERGY EXPLORATION AND PRODUCTION TENEMENTS
COOPER BASIN
State
Tenement
Interest
Location
Area (km2)
Operator
Activities
South Australia
PPL 204 (Sellicks)
25%
Onshore
2.0
Beach Energy
Production
PPL 205
(Christies / Silver Sands)
PPL 207 (Worrior)
PPL 220 (Callawonga)
PPL 224 (Parsons)
PPL 245 (Butlers)
PPL 246 (Germein)
PPL 247
(Perlubie/Perlubie Sth)
PPL 248
(Rincon/Rincon Nth)
PPL 249 (Elliston)
PPL 250 (Windmill)
PRLs 85-104
PRLs 231-233
PRL 237
PRLs 207-209
PRLs 183-190
25%
30%
25%
25%
25%
25%
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
4.3
6.4
5.5
1.8
2.1
0.1
Beach Energy
Production
Senex Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
25%
Onshore
1.5
Beach Energy
Production
25%
25%
25%
25%
30%
20%
19.165%
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
20%
Onshore
2.0
0.8
0.6
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
1,889
Beach Energy
Exploration
276
18
297
728
Beach Energy
Exploration
Beach Energy
Exploration
Beach Energy
Exploration
Beach Energy
Exploration
OTWAY BASIN
State
Tenement
Interest
Location Area (km2)
Operator
Activities
South Australia
PEL 494
Victoria
PEL 680
PRL 32
VIC/L22
VIC/L24
VIC/L30
VIC/L33
VIC/L34
VIC/P44
VIC/P76
PEP 168
PEP 171
Athena Gas Plant
30%
30%
30%
10%
50%
50%
50%
50%
50%
100%
50%
75%1
50%
Onshore
Onshore
Onshore
Offshore
Offshore
Offshore
Offshore
Offshore
Offshore
Offshore
Onshore
2,489
1,923
Beach Energy
Exploration
Beach Energy
Exploration
37
58
199
200
127
6.0
599
161
795
Beach Energy
Exploration
BHP
Ceased production
Cooper Energy
Production
Cooper Energy
Production
Cooper Energy
Development
Cooper Energy
Development
Cooper Energy
Exploration
Cooper Energy
Exploration
Beach Energy
Exploration
Onshore
1,974
Vintage Energy
Exploration
Onshore
n/a
Cooper Energy
Gas Processing
1 Subject to Heads of Agreement for a farm-in which will reduce Cooper Energy’s interest to 50%.
30
PORTFOLIO
GIPPSLAND BASIN
State
Victoria
Tenement
VIC/RL16
VIC/RL13
VIC/RL14
VIC/RL15
VIC/L32
VIC/P72
VIC/P75
Interest
Location
Area (km2)
Operator
Activities
100%
100%
100%
100%
100%
100%
100%
Offshore
Offshore
Offshore
Offshore
Offshore
Offshore
Offshore
134.0
Cooper Energy
Retention
67.0
67.0
67.0
201.0
269.0
802.0
Cooper Energy
Retention
Cooper Energy
Retention
Cooper Energy
Retention
Cooper Energy
Production
Cooper Energy
Exploration
Cooper Energy
Exploration
Supporting the Warrnambool Surf Life Saving Club
31
COOPER ENERGY ANNUAL REPORT 2021 DIRECTORS
CHAIRMAN
Mr John C. Conde AO
B.Sc. B.E(Hons), MBA
Independent
Non-Executive Director
Appointed 25 February 2013
MANAGING DIRECTOR
Mr David P. Maxwell
M.Tech, FAICD
Appointed 12 October 2011
INDEPENDENT
NON-EXECUTIVE DIRECTOR
Timothy G. Bednall
LLB (Hons)
INDEPENDENT
NON-EXECUTIVE DIRECTOR
Victoria (Vicky) J. Binns
B. Eng. (Mining – Hons 1), Grad Dip SIA,
Appointed 31 March 2020
FAusIMM, GAICD
Appointed 2 March 2020
Experience and expertise
Experience and expertise
Experience and expertise
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, 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),
Chairman of Dexus Wholesale
Property Fund (DWPF) (since 2020)
and Deputy Chairman of
Whitehaven Coal Limited ASX:
WHC (since 2007). Mr Conde is a
former Chairman of Bupa Australia
(2008 – 2018), and a 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.
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 Petroleum Limited and
Santos Limited. Mr Maxwell has
very successfully 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 is a Director of the
wholly owned subsidiaries of
Cooper Energy Limited. He is also
on the board of the Australian
Petroleum Production & Exploration
Association (since 2018) and the
Minerals and Energy Advisory
Council (South Australia
Government) (since 2019).
Special responsibilities
Mr Maxwell is Managing Director.
He is responsible for the day-to-day
leadership of Cooper Energy,
and is the leader of the Executive
Leadership Team. Mr Maxwell is
also Chairman of the HSEC
Committee (being a management
committee, not a Board committee).
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). He is also a board
member of QSP Residual
Recoveries LLP (in administration)
and a Director of Pooling Limited.
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 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.
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 October 2021). She is also
a Non-Executive Director of the
Carbon Marketing 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.
32
DIRECTORS
INDEPENDENT
NON-EXECUTIVE DIRECTOR
Ms Giselle M. Collins
B.Ec., ACA
INDEPENDENT
NON-EXECUTIVE DIRECTOR
Ms Elizabeth A. Donaghey
B.Sc., M.Sc.
Appointed 19 August 2021 subject to
confirmation by shareholders at the
Company’s 2021 AGM
Appointed 25 June 2018
NON-EXECUTIVE DIRECTOR
Mr Hector M. Gordon
B.Sc. (Hons)
Appointed 24 June 2017
Executive Director
26 June 2012 – 23 June 2017
INDEPENDENT
NON-EXECUTIVE DIRECTOR
Mr Jeffrey W. Schneider
B.Com.
Appointed 12 October 2011
Experience and expertise
Experience and expertise
Experience and expertise
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
Petroleum Limited. 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 Committees.
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 non-
executive director of Peak
Resources Limited ASX:PEK (since
2021), trustee director of the Royal
Botanic Gardens and Domain Trust
(since 2019), non-executive director
of Generation Life (since 2018),
non-executive director of Hotel
Property Investments Limited
ASX:HPI (since 2017) and nominee
Chairman for Indigenous Business
Australia in The Darwin Hotel Pty
Limited (since 2014).
Special responsibilities
Ms Collins was not a director during
the period ending 30 June 2021,
having joined the Board on
19 August 2021. Ms Collins is a
member of the Audit Committee and
the Risk & Sustainability Committee.
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 a Non-Executive
Director of the Australian Energy
Market Operator (AEMO) (since
2017) and a Non-Executive Director
of Ampol Limited (ASX: ALD)
(since 1 September 2021).
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 an 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 Director of Bass Oil
Limited ASX: BAS (since 2014).
Special responsibilities
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 19 August 2021 Mr Gordon
is the Chairman of the Risk
& Sustainability Committee and a
member of the Audit Committee.
33
COOPER ENERGY ANNUAL REPORT 2021 EXECUTIVE LEADERSHIP TEAM
MANAGING DIRECTOR
David Maxwell
M. Tech FAICD
ACTING CHIEF FINANCIAL
OFFICER
David Di Blasio
B.Sc., B.Com., CA, MBA
GENERAL MANAGER,
COMMERCIAL AND
BUSINESS DEVELOPMENT
Eddy Glavas
B.Acc. FCPA, MBA
GENERAL MANAGER,
PEOPLE AND
REMUNERATION
Ashley Haren
Dip. Bus. (HR/IR)
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.
Mr Haren joined Cooper Energy in
January 2021. He brings 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 oil and
gas 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 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 Petroleum Limited
and Santos Limited. Mr. Maxwell
has very successfully led many
large commercial, marketing and
business development projects.
Prior to joining Cooper Energy
Mr Maxwell worked with the
BG Group, where he led its 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, including
the Australian Petroleum Production
and Exploration Association –
Mr Maxwell is a recipient of the
Australian Gas Association Silver
Flame Award for his contribution
to the gas industry. In September
2019, he was named the recipient
of the 2019 John Doran Lifetime
Achievement Award for outstanding
long term achievement in the
Australian oil and gas industry.
Mr Di Blasio joined Cooper Energy
in 2019 as Finance Manager and
has managed all aspects of the
finance function. Prior to Cooper
Energy, he held senior finance roles
over a 13-year period with Santos
and before that worked in audit and
assurance at PwC.
Mr Di Blasio is a Chartered
Accountant and holds an MBA and
Bachelor of Commerce degree from
the University of South Australia.
CHIEF FINANCIAL OFFICER1
Virginia Suttell
B.Com. ACA GAICD, FGIA, FCIS
Ms Suttell joined Cooper Energy in
January 2017, bringing more than
25 years’ experience, including
20 years in publicly listed entities,
principally in group finance and
secretarial roles in the resources
and media sectors. This included
Chief Financial Officer and
Company Secretary for Monax
Mining Limited and Marmota Energy
Limited from 2007 to 2016, and
2007 to 2015 respectively.
Other previous appointments include
9 years at Austereo Group Limited,
including Group Financial Controller
from 2003 to 2006. A chartered
accountant, Ms Suttell’s other
previous employers include KPMG
and Price Waterhouse.
1 As announced on 7 July 2021, Ms Suttell
has resigned from Cooper Energy,
effective 30 September 2021.
34
COOPER ENERGY ANNUAL REPORT 2021 EXECUTIVE LEADERSHIP TEAM
GENERAL MANAGER,
PROJECTS AND
OPERATIONS
Michael Jacobsen
B. Eng. (Hons)
Mr Jacobsen has 28 years of
experience in upstream and
midstream oil and gas development
projects. He has held various
positions at Santos, Woodside and
BHPB Petroleum. Mr Jacobsen’s
experience includes managing
major capital works projects with
multi-discipline teams in the North
Sea, Asia, and Australia. He has
overseen the management of
subsea and FPSO developments,
fixed platforms and LNG plants.
Prior to joining Cooper Energy
Mr Jacobsen worked for
Santos as part of the leadership
team of the WA/NT business unit.
Mr Jacobsen has extensive
experience with oil field services
company Halliburton managing
subsea construction projects
throughout Asia and Australia.
COMPANY SECRETARY AND
GENERAL COUNSEL
Amelia Jalleh
BA, LLB (Hons), LLM
GENERAL MANAGER, HSEC
AND TECHNICAL SERVICES
Iain MacDougall
B.Sc. (Hons)
GENERAL MANAGER,
EXPLORATION AND
SUBSURFACE
Andrew Thomas
B.Sc. (Hons)
Ms Jalleh has more than 20 years
of experience in the international oil
and gas industry, including senior
corporate, commercial and legal
roles. Her experience spans
conventional and unconventional
projects, asset and portfolio
management, and international
M&A transactions.
Prior to joining Cooper Energy,
Ms Jalleh held the position of
Director, Business Development
Asia-Pacific for Repsol, based in
Singapore. Ms Jalleh has worked in
Australia, the Middle East, North
America and South East Asia in
roles with Repsol, Talisman Energy,
King & Spalding LLP and Santos.
Ms Jalleh holds a Masters of
Laws (University of Melbourne),
a Bachelor of Laws and Legal
Practice (Hons) (Flinders University
of South Australia) and a Bachelor
of Arts (Flinders University of
South Australia).
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.
Mr MacDougall has 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. He is a member of the
Society of Petroleum Engineers and
also serves on the Advisory
Board of the Australian School of
Petroleum at Adelaide University.
Mr Thomas is a successful and
experienced geoscientist who has
been involved with Australian and
International oil and gas 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
SE 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.
35
COOPER ENERGY ANNUAL REPORT 2021 KEY PERFORMANCE INDICATORS
FY13
FY14
FY15
FY16
FY17
FY18
FY19
FY20
FY21
Operations
Production
2P Proved and
Probable Reserves
Wells drilled
Exploration wells spudded
MMboe
0.49
0.59
0.48
0.46
0.96
1.49
1.31
1.56
MMboe
2.16
2.01
3.08
3.00
11.7
52.4
52.7
49.9
#
#
13
8
11
5
9
4
1
0
9
1
4
2
0
0
18
4
2.63
47.1
1
0
Reserve replacement ratio1 %
98%
71%
333%
18%
768% 2,380% (206%)
(56%)
(80%)
Financial
Sales revenue
$ million
53.4
72.3
39.1
27.4
39.1
67.5
75.5
78.1
131.7
Other income
$ million
2.3
2.8
1.9
0.9
EBITDA
$ million
22.3
36.9
(58.4)
(37.4)
1.6
1.9
4.9
4.2
19.8
7.2
49.9
7.5
(75.2)
23.5
Net profit before tax / (loss)
$ million
18.3
31.2
(18.8)
(26.0)
(7.0)
31.0
(13.2)
(110.0)
Net profit after tax / (loss)
$ million
1.3
22.0
(63.5)
(34.8)
(12.3)
27.0
(12.1)
(86.0)
Cash and cash equivalents
$ million
47.9
49.1
39.4
49.8
147.5
236.9
164.3
131.6
Other financial assets
$ million
20.2
26.0
1.9
1.0
0.7
42.6
21.7
0.6
Working capital
$ million
51.7
41.2
43.0
44.2
84.0
154.0
131.8
90.4
(33.5)
(30.0)
91.3
1.2
30.3
Accumulated profit
$ million
23.8
45.7
(17.7)
(52.6)
(64.9)
(37.9)
(49.9)
(136.0)
(166.0)
Franking credits
$ million
39.0
38.7
43.7
42.9
42.9
42.9
42.9
42.9
Total equity
$ million
137.2
167.8
103.9
91.6
285.0
443.9
433.7
351.1
Earnings per share
cents
0.4
6.4
(19.2)
(10.1)
(1.8)
1.8
(0.7)
(5.3)
42.9
325.8
(1.8)
Return on shareholder funds %
0.9%
14.4% (46.7%)
(38.0%)
(6.5%)
7.4% (2.6%)
(21.9%)
(8.9%)
Total shareholder return
%
(16.7%)
34.7% (51.5%)
(12.2%)
72.7%
6.0%
40.3% (30.6%)
(30.7%)
Average oil price
$/bbl
112.31
124.08
85.48
60.75
61.89
99.61
106.19
83.75
79.56
Capital as at 30 June
Share price
$
0.375
0.505
0.245
0.215
0.380
0.385
0.540
0.375
0.260
Issued shares
million
329.1
329.2
331.9
435.2
1,140.2
1,601.1
1,621.6
1,621.6
1,631.0
Market
$ million
123.4
166.3
81.4
93.6
433.3
616.4
875.5
608.1
Shareholders
#
5,284
5,122
5,103
4,931
6,292
6,622
6,758
8,094
424.1
9,355
1 Reserve replacement ratio calculated by net 1P reserve addition divided by annual production.
36
Cooper Energy Limited
and its controlled entities
FINANCIAL
REPORT
For the year ended 30 June 2021
Operating and Financial Review
Directors’ Statutory Report
Remuneration Report
Consolidated Statement of Comprehensive Income
Consolidated Statement of Financial Position
Consolidated Statement of Changes in Equity
Consolidated Statement of Cash Flows
Notes to the Consolidated Financial Statements
Group Performance
1. Segment reporting
2. Revenues and expenses
3.
4.
Income tax
Earnings per share
Working Capital
5. Cash and cash equivalents and term deposits
6. Trade and other receivables
7. Prepayments
8.
Inventory
9. Trade and other payables
10. Exploration assets held for sale
Capital Employed
11. Property, plant and equipment
12. Intangible assets
13. Exploration and evaluation assets
14. Oil and gas assets
15. Impairment
16. Provisions
17. Leases
Funding and Risk Management
18. Interest bearing loans and borrowings
19. Net finance costs
20. Contributed equity and reserves
21. Financial risk management
Group Structure
22. Interests in joint arrangements
23. Investments in controlled entities
24. Parent entity information
Other Information
25. Commitments for expenditure
26. Contingent liabilities
27. Share based payments
28. Related party disclosures
29. Remuneration of Auditors
30. Events after the reporting period
Directors’ Declaration
Independent Auditor’s Report to the Members
of Cooper Energy Limited
Auditor’s Independence Declaration to the
Directors of Cooper Energy Limited
Securities Exchange and Shareholder Information
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Corporate Directory
Inside back over
37
COOPER ENERGY ANNUAL REPORT 2021 OPERATING AND FINANCIAL REVIEW
For the year ended 30 June 2021
Operations
Cooper Energy Limited (“Cooper Energy” or the “Company”) generates revenue from production of gas from the Otway and Gippsland basins
and production of oil from the Cooper Basin. The Company’s current operations and interests include:
• offshore gas 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 (“Casino Henry”) gas fields;
• onshore oil production and exploration prospects in the western flank of the Cooper Basin, South Australia;
• the Athena Gas Plant (previously known as the Minerva Gas Plant) in the onshore Otway Basin, Victoria;
• the Manta gas and liquids field in the Gippsland Basin;
• the Annie gas discovery in the offshore Otway Basin; and
• exploration and appraisal prospects in the Otway, Gippsland and Cooper basins.
The Company is the Operator of all of its offshore gas activities and of the Athena Gas Plant.
Reserves and Contingent Resources
Proved and probable reserves (2P) at 30 June 2021 are assessed to be 47.1 MMboe compared with 49.9 MMboe at 30 June 2020. Contingent
resources (2C) at 30 June 2021 are assessed to be 33.9 MMboe compared with 34.9 MMboe at 30 June 2020. 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 2021, released 23 August 2021.
As at 30 June 20211
Gippsland Basin
Otway Basin
Cooper Basin
Total Cooper Energy
2P Proved and Probable Reserves
2C Contingent Resource
Gas
PJ
Oil & condensate
MMbbl
Total
MMboe
Gas
PJ
Oil & condensate
MMbbl
Total
MMboe
226.8
54.5
0.0
281.3
0.0
0.0
1.1
1.1
37.1
8.9
1.1
47.1
134.9
48.6
0.0
183.5
3.4
0.1
0.5
4.0
25.4
8.0
0.5
33.9
1 As announced on 23 August 2021. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by arithmetic sum
by category.
Workforce
At 30 June 2021, the Company had 88.5 full time equivalent (“FTE”) employees and 16.8 FTE contractors compared with 75.9 FTE employees
and 31.5 FTE contractors at 30 June 2020. The increase in employee numbers is attributable to resourcing growth of the Group’s operations, in
particular for the operational readiness of the Athena Gas Plant.
Contractor numbers have fluctuated in line with the project requirements of the Athena Gas Plant, Otway Phase 3 Development (“OP3D”) Select
Phase, Basker Manta Gummy (“BMG”) project and Casino Henry hydraulic flying lead and subsea control module electric flying leads (“CHASE”)
project for the FY21 works programs.
Health Safety Environment and Community
No Lost Time Injuries (“LTI”) were recorded for the period. This was an improvement over FY20 where one LTI was recorded. There were two
minor injuries sustained by contractors which resulted in a Total Recordable Incident Frequency Rate (“TRIFR”) of 6.92. This was up on FY20
which had a TRIFR of 3.53.
There were no reportable environmental incidents.
Production
Record oil and gas production of 2.63 MMboe was 69% higher than the prior year, mainly due to increased gas production from Sole following
reconfiguration works at the Orbost Gas Processing Plant (“OGPP”) undertaken during the second quarter of the financial year.
Total gas production of 15.1 PJ was 82% higher than the prior year. In the Gippsland Basin, increased Sole production resulted in a 395%
increase in gas production to 10.4 PJ. In the Otway Basin, natural field decline and processing interruptions in June contributed to a 20% decline
in gas production to 4.7 PJ (net to Cooper Energy).
Oil and condensate production of 158.7 kbbl was 19% lower than the prior year, mainly due to natural field decline.
Production by product and basin is summarised in the following tables.
38
COOPER ENERGY ANNUAL REPORT 2021 Operations continued
Production by product
Sales gas
Oil and condensate
Total production
Production by basin
Gippsland Basin
Sole: Sales gas
Otway Basin
Casino Henry: Sales gas
Casino Henry: Condensate
Minerva: Sales gas
Minerva: Condensate
Cooper Basin
Oil
Total production
PJ
kbbl
MMboe
PJ
PJ
kbbl
PJ
kbbl
kbbl
MMboe
FY20
8.3
196.5
1.56
FY20
2.1
5.9
2.8
0.3
0.8
193.0
1.56
FY21
15.1
158.7
2.63
FY21
10.4
4.7
1.8
–
–
156.9
2.63
Change
82%
(19%)
69%
Change
395%
(20%)
(36%)
(100%)
(100%)
(19%)
69%
Commercial
Key commercial activities during the financial year are summarised below.
Transition Agreement
As announced on 20 August 2020, Cooper Energy and APA Group (ASX: APA) entered into a Transition Agreement to provide the framework for
commencing the Sole Gas Sales Agreements (“GSAs”) and commissioning OGPP as early as possible. The Transition Agreement also provides
for revenue and cost sharing mechanisms during the commissioning phase and contributions from APA to Cooper Energy for the cost of sourcing
certain back-up gas supply if required. The Transition Agreement expires on 1 May 2022.
Commencement of Sole Gas Sales Agreements
Consistent with the objectives of the Transition Agreement, Cooper Energy commenced supply of gas to its customers under the long-term Sole
GSAs during the financial year. Gas supply commenced on 1 December 2020 and 1 January 2021 with total gas supply for the financial year of
12.7 PJ. Despite continuing gas processing shortfalls at OGPP, all Sole customer nominations were met. Average Sole customer nominations
during H2 FY21 were 47 TJ/day.
Securing third-party gas volumes to support Sole GSAs
To mitigate the risk of gas supply shortfalls and ensure all customer nominations are met, various risk mitigating actions were taken throughout
the year, including:
• entering various third-party gas purchase agreements;
• maintaining volumes held in gas pipeline storage; and
• agreeing arrangements to supply some gas volumes from Casino Henry into existing Sole GSAs.
Cooper Energy undertakes a portfolio approach to purchasing third-party gas when required to ensure the lowest cost and highest margin are
achieved. The average cost of third-party gas purchased during the financial year, net of the contribution received from APA, was materially less
than Cooper Energy’s average realised gas price.
Exploration, appraisal and development
Gippsland Basin
Cooper Energy is the Operator and 100% interest holder for all of its Gippsland Basin interests. As at 30 June 2021, these interests comprised:
a) VIC/L32, which contains the Sole gas field;
b) VIC/RL13, VIC/RL14 and VIC/RL15, which contain the Manta 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 and VIC/P75.
39
OPERATING AND FINANCIAL REVIEWFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Operations continued
Development: Sole Gas Project and OGPP
The Sole Gas Project involves development of the Sole gas field by Cooper Energy and upgrading of the OGPP by APA to process Sole gas.
The offshore project was completed by Cooper Energy during the 2019 calendar year within schedule, below budget, with zero lost time injuries and
with zero reportable environmental incidents. Total capital cost for the offshore project was $335 million compared with a budget of $355 million.
Commissioning of the OGPP by APA is continuing. The plant’s performance has been impaired by foaming and fouling in the sulphur recovery
unit’s two absorbers, which has constrained processing rates and required regular maintenance and cleaning. During Q2 FY21, reconfiguration
works were undertaken by APA to enable operation of the absorbers independently, in parallel or in series. These works provided greater
operational flexibility and the ability to conduct cleaning of absorbers while minimising interruption to production.
During the second half of the financial year, OGPP processing rates and stability improved. However, production of gas from the Sole gas field
continued to be constrained due to fouling within the two absorbers. By the end of the financial year, each absorber was being cleaned every two
weeks (i.e. one absorber cleaned every week) to stabilise and maximise the average production profile through winter.
Subsequent to financial year-end, Cooper Energy provided approval to APA for further capital works at OGPP to be undertaken during FY22.
The work program is designed to significantly improve plant performance and includes:
• installation of spray nozzles in the absorbers to suppress foaming and reduce fouling; and
• installation of solids removal technology to prevent fouling within the absorbers.
During Q4 FY21, significant testing was undertaken by APA at OGPP on solids removal technologies. The equipment tested is designed to
reduce sulphur particle size from the solution. This sulphur deposition (fouling) within the sulphur recovery unit’s absorbers and peripheral
equipment has led to the high frequency cleaning of the absorbers. The testing undertaken on the solids removal technology delivered promising
results regarding the ability to remove, in a controlled way, larger sulphur particles from the solution before they enter the absorbers.
The analysis to determine the underlying root cause of foaming and fouling at OGPP is continuing. In Q4 FY21, APA and Cooper Energy engaged
a specialist surfactant chemist to peer review the testing results and analysis previously undertaken. The surfactant chemist’s scope of work is
being overseen by a technical committee comprising APA and Cooper Energy representatives.
Exploration
The exploration focus in the Gippsland Basin has been on VIC/P75 in the Basin’s central area. The permit is surrounded by major fields, including
the Marlin, Snapper and Barracouta gas fields to the north and the Kingfish and Fortescue oil fields to the south and east.
Interpretation and depth conversion of the reprocessed 3D seismic data in VIC/P75 was completed and a prospect called Spineback was
identified. Resource and risk assessment of Spineback is underway.
In VIC/RLs 13, 14 and 15, the prospectivity under existing discoveries is being reviewed based on an improved understanding of depth
conversion in the Gippsland Basin from work in VIC/P75. In addition to the Manta Deep prospect, which could be drilled by deepening a future
Manta-3 appraisal well to approximately 4,500 metres, investigations are ongoing on similar prospectivity below the discovered Gummy field.
A suspension and extension of VIC/P72 was received from the National Offshore Petroleum Titles Administrator (“NOPTA”), with the permit’s
primary term now expiring in May 2023. VIC/P72 adjoins VIC/RL16, which holds the Patricia-Baleen gas field and associated subsea production
infrastructure connected to the OGPP. VIC/P72 is close to several Esso-operated oil and gas fields including Remora, Snapper, Sunfish and
Sweetlips, and the SGH Energy-operated Longtom gas field. Prospects identified in VIC/P72 are analogues to offset fields.
BMG abandonment
The Basker, Manta and Gummy fields (“BMG”) abandonment project involves decommissioning seven wells and associated subsea infrastructure
in the BMG fields in the Gippsland Basin. The BMG permits contain the proven Manta gas field and the Manta Deep prospect.
The BMG abandonment project entered the Front-End Engineering Design (“FEED”) stage, with activities focused on selecting optimal methodologies
and technologies for safe and cost-effective delivery of the decommissioning objectives. Regulatory documentation, including the Well Operations
Management Plan, was submitted to the regulator, the National Offshore Petroleum Safety and Environmental Management Authority (“NOPSEMA”) and
the review process is underway. Details of the scope of works and cost estimates will be announced after all details have been received and the required
assurance review is completed. Timing will be determined as part of NOPSEMA’s review, which we expect will include discussions with Cooper Energy.
In consultation with industry, Cooper Energy is considering NOPSEMA’s Decommissioning Compliance Strategy, which was released in April 2021.
Cooper Energy continues to liaise closely with the regulator and other stakeholders to ensure ongoing compliance with the regulatory requirements.
Otway Basin (Offshore)
The Company’s interests in the offshore Otway Basin as at 30 June 2021 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;
40
OPERATING AND FINANCIAL REVIEWFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Operations continued
d) a 100% interest in and Operatorship of exploration permit VIC/P76;
e) a 50% interest in and Operatorship of the Athena Gas Plant (onshore Victoria) which is jointly owned with Mitsui and is being
recommissioned to process gas from Casino Henry and other Otway Basin discoveries; and
f) a 10% non-operated interest in production licence VIC/L22 which holds the shut-in Minerva gas field, with BHP the Operator and
90% interest holder.
Exploration
Reprocessing of 3D seismic data covering VIC/P76, VIC/P44, VIC/L24, VIC/L30, VIC/L33 and VIC/L34 commenced, with completion targeted for
early FY22.
Geoscience studies progressed for the Elanora, Juliet, Nestor and Pecten East prospects, including review of the successful Artisan-1 exploration
well of Beach Energy Limited (“Beach”) in neighbouring VIC/P43. The studies have increased Cooper Energy’s confidence in the size and
prospectivity of Juliet and Nestor. Wells targeting these prospects will be assessed for inclusion in future drilling campaigns. All prospects show
strong seismic amplitude support for the presence of gas and are close to production infrastructure.
Suspension, extension and variations for VIC/P44 and VIC/P76 were received from NOPTA, with the permits’ primary terms now expiring in May
2023 and September 2024, respectively.
Development: Otway Phase 3 Development Project (“OP3D”)
OP3D involves development of the Annie gas discovery and Henry gas field to produce more than 120 PJ of gas through the Athena Gas Plant.
OP3D is currently in the Select Phase with planning for development drilling underway. The timing for a FID will be made having regard to
optimisation for market timing and funding.
Cooper Energy received Declaration as a Location approvals for the Annie discovery in VIC/P44 and VIC/P76 from NOPTA. These regulatory
approvals acknowledge the location of the Annie discovery and reserve the permits for conversion to future retention or production licenses.
Development: Athena Gas Plant Project
The Athena Gas Plant Project commenced in Q1 FY21 following COVID-19 related delays during the prior financial year. The project involves
commissioning the Athena Gas Plant to process gas and liquids from the Casino Henry fields and from future developments.
The upgrade is on schedule and on budget, with the work program approximately 80% complete at financial year-end. Mechanical completion
has been achieved and preparations commenced for commissioning and start-up readiness. Work also commenced on the pipeline cutover
which when complete will direct gas from the Casino Henry fields to the Minerva Pipeline which connects to the Athena Gas Plant.
First commissioning gas through the plant is expected in Q1 FY22 and cutover of processing from the Iona Gas Plant to the Athena Gas Plant is
expected in Q2 FY22 following the peak winter demand period. Once operational, the Athena Gas Plant will be an integral asset within Cooper
Energy’s gas portfolio. Expected benefits from re-commissioning the plant include:
• the ability to produce gas from the Casino Henry fields at a higher rate due to the plant’s lower inlet pressure relative to the Iona Gas Plant;
• lower operating costs relative to current tariffs paid for gas processed through the Iona Gas Plant;
• additional gas processing capacity (total plant capacity of ~150 TJ/day) to support Otway Basin gas developments such as OP3D and future
discoveries; and
• enhanced gas production and marketing flexibility, with the ability to offer firm gas supply and manage Sole customer requirements using
Cooper Energy’s Otway Basin gas if required.
Otway Basin (Onshore)
The Company’s interests in the onshore Otway Basin include licences in South Australia and permits in Victoria. Activities in the latter were
suspended pursuant to a Victorian State Government moratorium on onshore gas exploration, which was imposed in 2017. That moratorium has
been overturned by the Petroleum Legislation Amendment Act 2020 (Vic) with effect from 1 July 2021.
The Company’s interests in the onshore Otway Basin as at 30 June 2021 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;
b) a 50% interest in PEP 168 in Victoria with the remaining interest held by the Operator, Beach; and
c) a 75% interest in PEP 171 in Victoria, which may reduce to 50% on fulfilment of farm-in arrangements executed with joint venture partner and
Operator Vintage Energy Limited.
Exploration
Preparation for the Dombey 3D seismic acquisition in PEL 494 progressed during the financial year. The seismic acquisition is expected to be
conducted in FY22 and will cover the Dombey gas discovery in the Penola Trough.
The South Australian Department for Energy and Mining granted PEL 680 to Beach and Cooper Energy during the financial year. The five-year
work program consists of geological and geophysical studies and reprocessing of 2,700 km of 2D seismic.
Cooper Energy withdrew from the PEP 150 joint venture during the financial year.
41
OPERATING AND FINANCIAL REVIEWFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Operations continued
The Victorian Department of Jobs, Precincts and Regions is reviewing the revised work programs for PEP 168 and PEP 171, following the lifting
of the onshore Victorian exploration moratorium.
Cooper Basin
The Company’s interests in the Cooper Basin as at 30 June 2021 comprised:
a) a 25% interest in PRLs 85-104 (the “PEL 92 Joint Venture”) with the remaining interests held by the Operator, Beach;
b) a 30% interest in PRLs 231-233 (the “PEL 93 Joint Venture”), with the remaining interests held by the Operator, Beach;
c) a 20% interest in PRL 237, with the remaining interests held by Metgasco Limited and the Operator, Beach;
d) a 19.165% interest in PRLs 207-209 (formerly PEL 100), with the remaining interests held by Santos QNT Pty Limited and the Operator,
Beach; and
e) a 20% interest in PRLs 183-190 (formerly PEL 110), with the remaining interests held by the Operator, Beach.
Sale of oil interests to Bass Oil Limited
As announced by Bass Oil Limited (ASX: BAS, “Bass”) on 12 July 2021, agreement was reached for Bass to acquire Cooper Energy’s interest
in the Worrior oil field (PPL 207) and certain other exploration permits for $0.65 million. The transaction includes the Company’s 30% interest in
PRLs 231-233, the 20% interest in PRLs 183-190 and PRL 237, and 19.165% interest in PRLs 207-209. The transaction is subject to various
conditions precedent, including a Bass capital raising and regulatory approvals.
The sale of these oil interests demonstrates Cooper Energy’s ongoing focus on portfolio optimisation and divesting of assets considered non-core.
This focus will continue, and particularly in the context of Cooper Energy’s primary focus on commercialising gas resources for south-eastern Australia.
Development
One oil development well was drilled during the financial year, being the Callawonga-13 horizontal oil development well in PEL 92. The well was
drilled to a total depth of 3,226 metres with a lateral section of 1,106 metres in the primary target McKinlay Member. The preliminary assessment
of results indicated a net pay section of 605 metres across the lateral section. Installation of flowlines and artificial lift was completed and
Callawonga-13 commenced production in May.
Financial Performance
Cooper Energy recorded a statutory loss after tax of $30.0 million for the financial year which compares with a statutory loss after tax of $86.0
million recorded in the 2020 financial year. The 2021 financial year statutory loss included a number of items which affected the result by a total of
$4.1 million. These items comprise:
• other expense being the share of OGPP reconfiguration and commissioning works under the APA Transition Agreement of $11.2 million;
• non-cash restoration income of $7.2 million resulting from a change in the government bond rate used to discount the Patricia Baleen, BMG
and Minerva fields’ restoration provisions;
• adjustment to the gain on sale recognised on the sale of the OGPP due to transaction costs of $1.4 million;
• a non-cash impairment expense of $0.4 million; and
• tax impact of the above items of $1.8 million.
Calculation of underlying net profit after tax by adjusting for items unrelated to the underlying operating performance is considered to provide
a meaningful comparison of results between periods. Underlying net profit after tax and underlying EBITDAX are not defined measures under
International Financial Reporting Standards and are not audited. Reconciliations of net (loss)/profit after tax, underlying net profit after tax,
underlying EBITDAX and other measures included in this report to the Financial Statements are included at the end of this review.
Underlying EBITDAX of $30.0 million was 1% higher than the prior comparative period figure of $29.6 million.
The underlying loss after tax (exclusive of the items noted above) was $25.9 million, compared with an underlying loss after tax of $6.6 million in
the 2020 financial year. The factors which contributed to the movement between the periods were:
• higher gas sales revenue of $55.9 million attributed to commencement of production from the Sole gas field;
• lower oil sales revenue of $2.3 million derived from lower volumes;
• higher costs of sales of $63.2 million due to costs associated with the Transition Agreement and commencement of production. Production
expenses were higher by $36.0 million. Third-party product purchases of $13.4 million were incurred in 2021. Higher amortisation and
depreciation of $14.0 million due to commencement of Sole production. Royalties decreased by $0.2 million due to lower oil sales volumes;
• higher net finance costs of $7.6 million due to cessation of interest capitalisation on the Sole gas oil and gas asset;
• higher administration and other items of $4.7 million including exploration and business development costs, general administration costs and
foreign currency translation loss;
• lower exploration and evaluation write off of $2.5 million attributable to unsuccessful wells in the Cooper Basin; and
• higher tax benefit of $0.1 million.
42
OPERATING AND FINANCIAL REVIEWFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Financial Performance continued
Financial Performance
Production volume
Sales volume
Sales revenue
Gross profit
Gross profit / Sales revenue
Operating cash flow
Cash, other financial assets and investments
Reported loss after tax
Underlying loss after tax
Underlying loss before tax
Underlying EBITDAX*
MMboe
MMboe
$ million
$ million
%
$ million
$ million
$ million
$ million
$ million
$ million
FY21
2.6
3.0
131.7
14.1
10.7
8.1
92.6
(30.0)
(25.9)
(29.3)
30.0
FY20
Change
1.6
1.5
78.1
23.6
30.2
48.1
132.1
(86.0)
(6.6)
(30.5)
29.6
1.0
1.5
53.6
(9.5)
(19.5)
(40.0)
(39.5)
56.0
(19.3)
1.2
0.4
%
69%
100%
69%
(40%)
(65%)
(83%)
(30%)
65%
(293%)
4%
1%
* Earnings before interest, tax, depreciation, amortisation, restoration, exploration and evaluation expense and impairment
All numbers in tables in the Operating and Financial Review have been rounded. As a result, some total figures may differ insignificantly from
totals obtained from arithmetic addition of the rounded numbers presented.
Cash and cash equivalents balance decreased by $39.0 million over the period as summarised in the following chart.
Operating cashflows for the period were $8.0 million comprising:
• cash generated from operations of $48.9 million;
• general administration costs of $14.3 million;
• restoration costs of $5.3 million;
• Petroleum Resource Rent Tax (PRRT) payments of $11.1 million; and
• net interest paid of $10.2 million.
Financing, investing and other cash flows for the period were $48.3 million and included:
• exploration, development and property, plant and equipment costs of $34.6 million, mainly in relation to the Athena Gas Plant,
Casino Henry OP3D Select Phase, general exploration and evaluation activity and the implementation of corporate systems;
• repayment of lease liability $1.0 million;
• repayment of borrowings of $11.4 million; and
• foreign exchange differences and other of $1.3 million.
Movements in cash and cash equivalents
30 June 2021 vs 30 June 2020
+113.6
(14.3)
(5.3)
48.9
(11.1)
(10.2)
(17.8)
(1.7)
(5.7)
(9.4)
(1.0)
139.6
$ million
Total cash and
cash equivalents,
other financial
assets and
investments
132.2
0.6
Other
financial
assets and
investments
131.6
Cash and
cash
equivalents
Total cash and
cash equivalents,
other financial
assets and
investments
92.5
(11.4)
(1.3)
1.2
Other financial
assets and
investments
91.3
Cash and
cash
equivalents
Operating
8.0
Other
(48.3)
June-20 Operations General
admin
Restoration
costs
PRRT
Interest
Cash after
operating
cash flows
CAPEX–
PPE
CAPEX–
Intangibles
CAPEX–
E&E
CAPEX–
Development
Payments
for lease
liabilities
Repayment
of
borrowings
FX &
Other
June-21
43
OPERATING AND FINANCIAL REVIEWFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
Financial Position
Financial Position
Total assets
Total liabilities
Total equity
Net debt
Assets
$ million
$ million
$ million
$ million
FY21
978.5
652.7
325.8
126.7
FY20
1,029.9
678.8
351.1
97.8
Change
(51.4)
(26.1)
(25.3)
28.9
%
(5%)
(4%)
(7%)
30%
Total assets decreased by $51.4 million from $1,029.9 million to $978.5 million.
At 30 June 2021 the Company held cash and cash equivalents of $91.3 million and investments of $1.3 million.
Exploration and evaluation assets are $0.4 million higher than the previous period mainly due to additions partially offset by impairments and
reclassification of $1.8 million to Exploration Assets Held for Sale which are presented as separate line in the Consolidated Statement of
Financial Position.
Oil and gas assets decreased by $45.8 million from $616.0 million to $570.2 million mainly as a result of amortisation and the re-set of
restoration provisions.
Total Liabilities
Total liabilities decreased by $26.1 million from $678.8 million to $652.7 million.
Provisions decreased by $28.0 million from $394.6 million to $366.6 million. Restoration provisions decreased $28.5 million from $392.2 million to
$363.7 million, with the decrease being attributable mainly to $17.5 million for changes in government bond rates, $8.4 million for payments, $1.2
million reclassified to Liabilities Held for Sale partially offset by accretion charges of $3.2 million. Employee provisions increased by
$0.5 million from $2.4 million to $2.9 million.
Interest bearing loans and borrowings decreased by $11.4 million from $229.4 million to $218.0 million. This represents repayments made to the
reserve-based lending facility.
Total Equity
Total equity decreased by $25.3 million from $351.1 million to $325.8 million. In comparing equity at 30 June 2021 to 30 June 2020 the key
movements were:
• higher contributed equity of $1.8 million due to shares issued on vesting of performance rights and share appreciation rights during the period;
• higher reserves of $2.9 million due to the unwinding of equity incentives to employees; and
• higher accumulated losses of $30.0 million due to the statutory loss for the period.
Strategy and Outlook
Cooper Energy’s purpose is to contribute to Australia’s sustainable energy future by commercialising gas, oil and other resources for domestic
markets. We operate with an emphasis on care, shareholder value and sustainability.
Cooper Energy will deliver this by:
• establishing a portfolio of low cost, long-term gas and oil production assets;
• growing through a combination of acquisition, development and exploration;
• building future resilience by prioritising Environment, Sustainability and Governance (“ESG”) and investing in sustainable energy projects;
• leveraging and developing our people, stakeholder relationships and capabilities where we operate; and
• balancing risk by sharing opportunities, partnering and achieving good commercial outcomes.
Planned activities for the FY22 financial year for the ongoing delivery of Cooper Energy’s strategy will be:
• participating in APA’s delivery of the next phase of capital works at OGPP which aim to increase production rates and improve stability;
• commissioning the Athena Gas Plant, which will become an integral asset within Cooper Energy’s gas portfolio and deliver benefits such as
higher processing rates for the Casino Henry fields, lower operating costs and the ability to offer firm gas supply to customers;
• being FID ready for OP3D which involves development of the Annie gas discovery and Henry gas field to produce more than 120 PJ of gas
through the Athena Gas Plant; and
• progressing other exploration, appraisal and development activities within Cooper Energy’s existing portfolio of growth opportunities.
44
OPERATING AND FINANCIAL REVIEWFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Funding and Capital Management
At 30 June 2021, the Company had cash reserves of $91.3 million and drawn debt of $218.0 million. The Company has a reserves-based
lending debt facility to fund a portion of the Sole gas field development with a limit of $218.0 million. The facility can be used for general corporate
purposes after project completion. The Company has additional liquidity of approximately $15.0 million through a working capital facility to be
used for general business purposes, of which $8.8 million has been utilised in respect of bank guarantees.
As announced on 30 June 2021, Cooper Energy and its lenders agreed adjustments to some terms and conditions of the debt facility.
The documentation was signed on 26 July 2021. The adjustments include realignment of principal repayments through to expiry of the Transition
Agreement on 1 May 2022 and re-sculpting of repayments through to maturity. The adjustments align the debt facility with a re-based production
level of 40– 45 TJ/day for OGPP and preserve liquidity to enable continuing advancement of the growth projects.
Further information is detailed in the Going Concern basis section on page 48 of the Financial Statements.
Risk Management
The Company manages risks in accordance with its risk management policy with the objective of ensuring risks inherent in oil and gas
exploration and production activities are identified, measured and then managed or kept as low as reasonably practicable. The Executive
Leadership Team performs risk assessments on a regular basis and a summary is regularly reported to the Risk & Sustainability Committee of
the Board. This Committee approves and oversees an internal audit program undertaken internally and/or in conjunction with appropriate external
industry or field specialists.
Appropriate policies and procedures are continually being developed and updated to manage these risks.
Risk
Description
Exploration
Exploration is a speculative activity with an associated risk of discovery to find oil and gas in commercial quantities
and a risk of development. If Cooper Energy is unsuccessful in locating and developing or acquiring new reserves and
resources that are commercially viable, this may have a material adverse effect on future business, results of operations
and financial conditions.
Cooper Energy utilises established methodologies and experienced personnel to evaluate prospects and manage the
risk associated with exploration. The Company also ensures all major exploration decisions are subjected to assurance
reviews which include external experts and contractors where appropriate.
Development and
Production
Development and production of oil and gas projects may be exposed to low side reserve outcomes, cost overruns,
production decrease or stoppage, which may result from facility shutdowns, mechanical or technical failure and other
unforeseen events. Cooper Energy undertakes technical, financial, business, and other analysis in order to determine
a project’s readiness to proceed from an operational, commercial and economic perspective. Even if Cooper Energy
recovers commercial quantities of oil and gas, there is no guarantee that a commercial return can be generated.
Regulatory
All major development investment decisions are subjected to assurance reviews which include external experts and
contractors where appropriate. For projects in production, reserves are formally reviewed and reported annually.
Cooper Energy operates in a highly regulated environment and complies with regulatory requirements. There is a risk
that regulatory approvals are withheld or take longer than expected, or that unforeseen circumstances arise where
requirements may not be adequately addressed in the eyes of the regulator and costs may be incurred to remediate
perceived non-compliance and/or obtain approval(s). The Company’s business or operations may be impacted by
changes in personnel and Governments, or in monetary, taxation and other laws in Australia or overseas.
45
OPERATING AND FINANCIAL REVIEWFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Risk Management continued
Risk
Market
Description
The global oil market and Australian domestic gas market are subject to fluctuations of demand and supply, and as a
consequence, price. The risk of material changes to the demand for oil and gas produced by the Company’s business
exists from sources such as demand destruction, changes in energy consumption preferences and demand and
supply-side disruption such as an expansion of alternative, competitive supply sources. If realised, these may result in
reduced sales volume and sales revenue with consequent impact on the efficiency of operations and the Company’s
financial condition.
In the near term this risk is managed through the Company’s gas contracting strategy. The Company maintains ‘long’
contract coverage such that the major share of its available reserves is contracted, typically under gas sales agreements
with a term of at least four years. Stability of cash flow is protected through terms which encourage reliable demand
from customers and which include take-or-pay clauses to ensure minimum annual cash flows. Uncontracted gas carries
exposure to favourable or unfavourable price movements. The greater share of the Company’s uncontracted gas is in
the offshore Otway Basin where the Athena Gas Plant Project is being conducted to facilitate the securing of longer term
contracts supported by more favourable processing terms.
Cooper Energy monitors developments and changes in the international oil and domestic gas markets to enable the
Company to be best placed to address changes in market conditions. This activity includes ongoing research and
analysis of future demand and supply for energy, most particularly gas, in south-east Australia.
Oil and gas prices
Future value, growth and financial conditions are dependent upon the prevailing prices for oil and gas. Prices for oil and
gas are subject to fluctuations and are affected by numerous factors beyond the control of Cooper Energy.
Cooper Energy monitors and analyses the oil and gas markets and seeks to reduce price risk where reasonable
and practical. The Company has policies and procedures for entering into hedging contracts to mitigate against the
fluctuations in oil price and exchange rates. Gas price risk is assessed within the context of the Company’s ongoing
modelling of the south-east Australian energy market and through its gas contracting strategy which prioritises long term
agreements and appropriate indexation and price review clauses.
Operations
There are a number of risks associated with operating in the oil and gas industry. The occurrence of any event associated
with these risks could result in substantial losses to the Company that may have a material adverse effect on Cooper
Energy’s business, results of operations and financial condition.
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 contracts. Cooper Energy operates with a comprehensive range of operating and
risk management plans (updated in FY21 to reflect risks associated with COVID-19) and an enterprise-wide integrated
management system to ensure safe and sustainable operations.
Counterparties
The ability of Cooper Energy to achieve its stated objectives can be impacted by the performance of counterparties
under material agreements the Company has entered into (including joint venture and gas sales agreements). If any
counterparties do not meet their obligations under these agreements, this may impact on operations, business and/or
financial conditions.
Cooper Energy monitors performance across material contracts against contractual obligations to minimise counterparty
risk and seeks to include terms in agreements which mitigate such risks. Cooper Energy also conducts due diligence
on counterparties as appropriate, including financial due diligence. The Company’s gas contracting strategy expressly
focuses on financially robust organisations assessed as being reliable gas customers within the target energy markets
and supported by the Company’s and third party research.
Reserves
Oil and gas reserves are expressions of judgement based on knowledge, experience and industry practice. These
estimates may alter significantly or become uncertain when new information becomes available and/or there are material
changes of circumstances which may result in Cooper Energy altering its plans which could have a positive or negative
effect on Cooper Energy’s operations.
Reserves and Contingent Resources estimation is consistent with the definitions and guidelines in the Society of
Petroleum Engineers (SPE) 2018 Petroleum Resources Management System (PRMS). The assessment of Reserves and
Contingent Resources may also undergo independent review.
46
OPERATING AND FINANCIAL REVIEWFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Risk Management continued
Risk
Description
Environment
Cooper Energy’s exploration, development and production activities are subject to state, national and international
environmental laws and regulations. Oil and gas exploration, development and production can be potentially
environmentally hazardous giving rise to substantial costs for environmental rehabilitation, damage control and losses.
Access to Capital
Restoration
liabilities
Cooper Energy has a comprehensive approach to the management of risks associated with environment which is
embedded as a core part of our approach to health, safety, environment and community. This approach includes
standards for asset reliability and integrity, technical and operational competency and emergency response preparedness.
Cooper Energy must undertake significant capital expenditure in order to fund field, exploration, appraisal, development
and restoration requirements. Limitations on access to adequate funding could have a material adverse effect on the
business, results from operations, financial conditions and prospects. Cooper Energy’s business and, in particular,
development of large-scale projects, relies on access to capital. There can be no assurance that sufficient access to
capital will be available on acceptable terms or at all.
Cooper Energy endeavours to ensure that the best source of funding is obtained to maximise shareholder value, having
regard to prudent risk management supported by economic and commercial analysis of all business undertakings.
Cooper Energy has certain obligations in respect of decommissioning of its fields, production facilities and related
infrastructure. These liabilities are derived from legislative and regulatory requirements concerning the decommissioning
of wells and production facilities, and require Cooper Energy to make provisions for such decommissioning and the
abandonment of assets. Provisions for the costs of this activity are informed estimates and there is no assurance that the
costs associated with decommissioning and abandoning will not exceed the amount of long-term provisions recognised to
cover these costs.
Cooper Energy recognises restoration provisions after construction and conducts a review on a semi-annual basis.
Any changes to the estimates of the provisions for restoration are recognised in line with accounting standards.
Community
Cooper Energy conducts gas and oil exploration, development, and production operations. We process gas near regions
with residential, environmental, cultural, and economic significance. Loss of community confidence in the Company may
adversely affect Cooper Energy’s capacity to execute its plans on behalf of the State and Federal Governments.
Cooper Energy engages extensively with local communities to build and maintain awareness, understanding and support
for its operations and plans. We form long term trusted relationships with local communities and generate awareness of
the economic benefits to the community and the nation.
Elements of engagement include:
• sponsorship and donations made to local community organisations;
• face to face meetings, online meetings, group meetings, emails and phone calls with:
- local office holders and elected representatives of local, state, and federal governments;
- local community groups via town hall meetings and community information sessions;
- fishing groups and other marine users; and
- local farmers and others who are located nearby our operations;
• publication of information regarding the Company’s activities and plans including the maintenance of a ‘Community’
page on the Company’s website; and
• engagement with local media, including the use of social media.
47
OPERATING AND FINANCIAL REVIEWFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Risk Management continued
Risk
Description
Cooper Energy has taken an industry leading position in becoming the first Australian upstream gas company to become
carbon neutral in FY20 by fully offsetting Scope 1, Scope 2 and the controllable fraction of Scope 3 emissions using high
quality Australian Carbon Credit Units (ACCUs) generated from the Morella Biodiversity project in South Australia. The
Company was recognised for this achievement in being awarded the 2020 SA Premier’s Award for Environment in its
industry category. Subsequently the Company has achieved Climate Active organisational certification for this net zero
position and we will strive to both maintain this net zero position and to reduce the absolute quantum of our emissions.
The Company recognises that direct physical and indirect non-physical impacts of climate change may affect our
operations and the markets into which we sell our gas and oil. Potential direct risks include those arising from increased
severe weather events, longer-term changes in climate patterns, sea level rise, and increased frequency and severity
of bushfires.
Indirect risks arise from a variety of legal, policy, technology, and market responses to the challenges that climate change
poses as society transitions to a lower emissions future. These risks may impact the demand for and competitiveness of
the Company’s products and the Company’s appeal as an investment, employer and community member.
Assessment and response to these risks is undertaken on three fronts:
1) understanding, managing and mitigating the risks presented by direct physical impacts;
2) understanding, managing and mitigating the impact of climate change and emissions policy on the demand for the
Company’s products (“market risk”); and
3)
identification of means by which the Company can reduce its direct emissions and lessen its overall emissions impact.
In respect of market risk, the Company’s strategy means its gas assets possess a low exposure to the possibility of
demand loss from climate change. A favourable market for sale of the Company’s gas reserves and resources has been
confirmed and is expected to continue given demand and supply forecasts for its chosen market of south-east Australia
and the role gas is expected to play as a conventional and transition energy source for firming variable renewable power
generation in a lower emissions world.
The Company’s portfolio of gas assets is concentrated in south-eastern Australia and reflects its screening criteria which
requires superior cost competitiveness in delivered gas and a foreseeable pathway to development.
Australian government forecasts (Australian Energy Market Operator; AEMO) project a widening gap between gas
demand and supply in south-east Australia. Production from the region’s existing sources of supply is projected to decline
significantly over the coming 10 years, while demand is forecast to remain flat over that period, leading to a growing
supply demand imbalance.
The merits of gas as a clean-burning energy source, and as a firming supply to provide dispatchable power to support
variable renewable energy, are expected to support greater use of gas compared with other fossil fuels. Gas is expected
to continue to be a principal source of energy for conventional heating and cooking applications and a critical input
for industrial uses including fertiliser and other agricultural chemicals, refrigerants, plastics, glass manufacture, food
processing and pharmaceuticals.
Natural gas is viewed as a key element supporting society’s sustainable energy transition and forecasts show an
increasing global demand for gas over the medium to long-term.
The Company measures and reports its emissions and seeks to reduce its emissions impact. These results are
published in its annual Sustainability Report and are aligned with the Taskforce for Climate related Financial Disclosures
(TCFD) criteria.
The focus of the Company’s strategy on conventional gas production, located in south-east Australia close to its market in
south-east Australia, is conducive to lower emissions gas supply.
Climate and
Sustainability
48
OPERATING AND FINANCIAL REVIEWFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Risk Management continued
Risk
COVID-19
Description
Cooper Energy continued its response to the COVID-19 pandemic in line with its focus on:
• prioritising the safety and welfare of its employees and their families, together with that of contractors, suppliers and the
communities within which it operates; and
• assessing, monitoring and managing risks to the continuity of the business.
The Pandemic Response Team, established in March 2020, continued its work through FY21 overseeing the Company’s
response to the COVID-19 pandemic. This team includes representatives from all sites and takes input from an
independent medical practitioner. Our response has included implementing robust work from home arrangements with
on-site staffing requirements limited to minimal IT support attendance when required at office locations, in line with state
government health directions and restrictions. Construction works at the Cooper Energy-operated Athena Gas Plant in
Victoria were able to progress with additional specific risk control measures in place to mitigate any infection risk and to
comply with State government health directions and lockdown/travel restrictions.
The work from home arrangements were used during the various lockdowns in Victoria, South Australia and Western
Australia during the year and remain ready to be reinstated at short notice as required.
All of the Company’s gas production is via unmanned subsea installations, which are operated remotely via the relevant
plant onshore control room. Accordingly, transitioning the Company into and out of work from home has had no impact on
production levels. Emergency response procedures have been tested using fully remote processes.
The Athena Gas Plant is anticipated to commence processing the Company’s gas in Q1 FY22. Robust procedures have
been implemented to minimise the risk of COVID-19 impacting processing at that Plant.
The COVID-19 pandemic has been assessed as not being among the Company’s key corporate risks. However,
it has affected the business indirectly through the impact on energy prices, supply chains and restrictions on travel.
The Pandemic Response Team continues to monitor and advise the Managing Director and Executive Leadership Team
on ongoing potential COVID-19-related threats to the business and appropriate preventative actions and responses.
People & Culture
Cooper Energy’s sustainable success is underpinned by attracting and retaining people with the right skills and
behaviours, who work to the “one team” ethos to deliver base business and growth opportunities. Failure to attract,
retain and develop such capability may constrain the achievement of business objectives.
Cooper Energy has established employment conditions, practices, frameworks, values, and environments designed to
engage, secure and incentivise employees to perform at their best and build their careers. Metrics are in place to monitor
employee engagement and these are regularly reviewed by the Executive Leadership Team and the Board.
49
OPERATING AND FINANCIAL REVIEWFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 OPERATING AND FINANCIAL REVIEW
For the year ended 30 June 2021
Reconciliations for net profit/(loss) to Underlying net profit/(loss) and Underlying EBITDAX
Reconciliation to Underlying loss
Net loss after income tax
Adjusted for:
Liquidated damages
OGPP reconfiguration and commissioning works
Restoration (income)/expense
Adjustment to gain on sale
Impairment
Tax impact of underlying adjustments
Underlying (loss)/profit
Reconciliation to Underlying EBITDAX*
Underlying loss
Add back:
Tax impact of underlying adjustments
Net finance costs
Accretion expense
Tax expense
Depreciation
Amortisation
Exploration and evaluation expense
Underlying EBITDAX*
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
FY21
(30.0)
-
11.2
(7.2)
1.4
0.4
(1.8)
(25.9)
FY21
(25.9)
1.8
10.3
3.3
(3.4)
1.9
41.5
0.6
30.0
FY20
(86.0)
(19.8)
-
14.1
-
107.5
(22.4)
(6.6)
FY20
(6.6)
22.4
1.8
4.0
(23.9)
2.3
26.5
3.1
29.6
Change
56.0
19.8
11.2
(21.3)
1.4
(107.1)
20.6
(19.3)
%
65%
100%
100%
(151%)
100%
(100%)
92%
(293%)
Change
%
(19.3)
(293%)
(20.6)
8.5
(0.7)
20.5
(0.4)
15.0
(2.5)
0.4
(92%)
472%
(18%)
86%
(17%)
57%
(81%)
1%
* Earnings before interest, tax, depreciation, amortisation, restoration, exploration and evaluation expense and impairment.
50
OPERATING AND FINANCIAL REVIEWFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 DIRECTORS’ STATUTORY REPORT
For the year ended 30 June 2021
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 2021,
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
Mr David P. Maxwell
M.Tech, FAICD
Managing Director
Appointed 12 October 2011
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, 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), Chairman of Dexus Wholesale Property Fund
(DWPF) (since 2020) and Deputy Chairman of Whitehaven Coal Limited ASX: WHC (since 2007). Mr Conde is
a former Chairman of Bupa Australia (2008–2018), and a 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
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 Petroleum Limited and Santos Limited. Mr Maxwell has very
successfully 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 is a Director of the wholly owned subsidiaries of Cooper Energy Limited. He is also on the board
of the Australian Petroleum Production & Exploration Association (since 2018) and the Minerals and Energy
Advisory Council (South Australia Government) (since 2019).
Special responsibilities
Mr Maxwell is Managing Director. He is responsible for the day-to-day leadership of Cooper Energy, and is
the leader of the Executive Leadership Team. Mr Maxwell is also Chairman of the HSEC Committee (being a
management committee, not a Board committee).
51
COOPER ENERGY ANNUAL REPORT 2021 1. Directors continued
Mr Timothy G. Bednall
LLB (Hons)
Independent Non-Executive
Director
Appointed 31 March 2020
Ms Victoria J. Binns
B. Eng (Mining – Hons 1),
Grad Dip SIA, FAusIMM, GAICD
Independent Non-Executive
Director
Appointed 2 March 2020
Ms Giselle M. Collins
BeC. Economics, CA, GAICD
Independent Non-Executive
Director
Appointed 19 August 2021
subject to confirmation at the
Company’s 2021 AGM
52
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). He is also a board
member of QSP Residual Recoveries LLP (in administration) and a Director of Pooling Limited.
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.
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 October 2021). She is also a Non-Executive Director of the Carbon Marketing 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.
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 non-executive director of Peak Resources Limited ASX:PEK (since 2021), trustee
director of the Royal Botanic Gardens and Domain Trust (since 2019), non-executive director of Generation
Life (since 2018), non-executive director of Hotel Property Investments Limited ASX:HPI (since 2017) and
nominee Chairman for Indigenous Business Australia in The Darwin Hotel Pty Limited (since 2014).
Special responsibilities
Ms Collins was not a director during the period ending 30 June 2021, having joined the Board on
19 August 2021. Effective 19 August 2021 Ms Collins is a member of the Audit Committee and the Risk
& Sustainability Committee.
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 1. Directors continued
Ms Elizabeth A. Donaghey
B.Sc., M.Sc.
Independent Non-Executive
Director
Appointed 25 June 2018
Mr Hector M. Gordon
B.Sc. (Hons) FAICD
Independent Non-Executive
Director
26 June 2012 – 23 June 2017
Non-Executive Director
Appointed 24 June 2017
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 a Non-Executive Director of the Australian Energy Market Operator (AEMO) (since 2017).
Effective 1 September 2021 Ms Donaghey will join the Ampol Limited (ASX: ALD) board as an Independent
Non-Executive Director.
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.
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 an 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 Director of Bass Oil Limited ASX: BAS (since 2014).
Special responsibilities
Mr Jeffrey W. Schneider
B.Com
Independent Non-Executive
Director
Effective 19 August 2021 Mr Gordon is the Chairman of the Risk & Sustainability Committee and
a member of the Audit 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 Petroleum Limited. He has extensive corporate governance and board experience as
both a Non-Executive Director and chairman in resources companies.
Appointed 12 October 2011
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.
53
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 1. Directors continued
Ms Alice J. Williams
B.Com, FAICD, FCPA, CFA
Independent Non-Executive
Director
Appointed 28 August 2013
Retired 12 November 2020
Experience and expertise
Ms Williams has over 30 years of senior management and board level experience in corporate, investment
banking and Government sectors.
Ms Williams has been a consultant to major Australian and international corporations as a corporate advisor
on strategic and financial assignments. Ms Williams has also been engaged by Federal and State based
Government organisations to undertake reviews of competition policy and regulation. Prior appointments
include Director of Airservices Australia, Guild Group, Port of Melbourne Corporation, Telstra Sale Company,
V/Line Passenger Corporation, State Trustees, Western Health and the Australian Accounting Standards
Board. Ms Williams is also a former council member of the Cancer Council of Victoria.
Current and other directorships in the last 3 years
Ms Williams is a Non-Executive Director of Djerriwarrh Investments Ltd, Defence Health (since 2010), Mercer
Investments Australia Ltd and not for profit Tobacco Free Portfolios (since 2018). Until 2020 Ms Williams was
a Member of the Foreign Investment Review Board and a Non-Executive Director of Equity Trustees Ltd.
She was also a Non-Executive Director of the Victorian Funds Management Corporation for the period 2008
to 2018.
Special responsibilities
Prior to her retirement, Ms Williams was the Chairman of the Audit Committee and a member of the
Risk & Sustainability Committee.
2. Company secretary
Ms Amelia Jalleh B.A., LLB (Hons), LLM was appointed to the position of Company Secretary and General Counsel effective from 9 August
2019. Ms Jalleh brings more than 20 years’ international oil and gas experience in senior corporate, commercial and legal roles. Her experience
spans conventional and unconventional projects, asset and portfolio management, and international M&A transactions. Prior to joining Cooper
Energy, Ms Jalleh held the position of Director, Business Development Asia-Pacific for Repsol, based in Singapore. Ms Jalleh has worked in
Australia, the Middle East, North America and South East Asia in roles with Repsol, Talisman Energy, King & Spalding LLP and Santos.
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
Meetings
People &
Remuneration
Committee
Meetings
Governance &
Nomination
Committee
Meetings
Mr J. Conde
Mr D. Maxwell
Mr T. Bednall
Ms V. Binns
Ms E. Donaghey
Mr H. Gordon
Mr J. Schneider
Ms A. Williams*
A
11
11
11
11
11
11
11
8
B
11
11
11
11
11
11
11
8
A
-
-
1
5
2
5
5
3
A = Number of meetings attended.
B
-
-
1
5
2
5
5
3
A
-
-
4
4
4
4
-
2
B
-
-
4
4
4
4
-
2
A
4
-
4
4
4
-
4
-
B
4
-
4
4
4
-
4
-
A
2
-
2
-
2
-
2
-
B
2
-
2
-
2
-
2
-
B = Number of meetings held during the time the Director held office, or was a member of the Committee, during
the year (noting that Committee membership was revised three times during the financial year – with effect on and
from 13 November 2020, with effect on and from 1 February 2021, and with effect on and from 1 April 2021).
*Ms A. Williams resigned as Non-Executive Director on 12 November 2020.
54
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited)
Information about the remuneration of the Company’s key management personnel for the financial year ended 30 June 2021 is set out in the
Remuneration Report. The information in the Remuneration Report has been audited as required by the Corporations Act 2001 (Cth) and forms
part of the Directors’ Report.
Introduction to Remuneration Report from the Chairman of the People & Remuneration Committee
Dear Shareholder
As has been well described earlier in this Report to shareholders, the 2021 financial year has been a challenging period for the Company.
This Remuneration Report is presented against this background and includes details of company performance against key metrics. It also sets
out how, as a consequence, the Company’s remuneration outcomes have been impacted.
We will seek shareholders’ support for the Remuneration Report at the 2021 Annual General Meeting. This report is an important element of the
Company’s annual reporting. It documents the Company’s remuneration framework and guiding principles. It also details the remuneration outcomes
for the Board and key management personnel and enables comparison of these remuneration outcomes with the Company’s performance.
The People & Remuneration Committee believes that the 2021 remuneration outcomes are appropriate taking into account the Company’s
performance and the employment market generally.
Remuneration Report context: 2021 Financial Year
The Company’s performance in the 12 months to 30 June 2021 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.
Cooper Energy met the targets of its Corporate Scorecard in the category of Health, Safety, Environment and Community as well as the category of
People & Enablers. The Company failed to meet targets in the categories of Production & Revenue, Project Delivery and Growth. The Company’s
share price decreased by 31% over the 2021 financial year, reflecting the challenging operating and external environment over the period.
Remuneration developments
A remuneration framework which attracts, encourages, rewards and retains talent is an important foundation that can enable the Company
to achieve superior total shareholder returns. During the past year the People & Remuneration Committee has reviewed each element of
the remuneration framework and concluded that the current framework is meeting its intended objectives to attract and retain high calibre
employees as well as providing incentives to deliver superior performance and encourage behaviours consistent with the Cooper Energy Values.
Consequently, no changes to the remuneration framework are proposed for the 2022 financial year.
Remuneration outcomes
Fixed Annual Remuneration: There will be no increases to Base Salary for the Managing Director, the Executive Leadership Team and staff
generally except for those who have increased job responsibilities or in the case of general staff, represent a pay anomaly requiring adjustment.
Any such increases will be consistent with benchmarking data within the Resources Industry (incorporating the Hydrocarbon sector). Fixed
Annual Remuneration will be adjusted as a consequence of increases to statutory superannuation contribution effective 1 July 2021.
Short Term Incentive Payments (STIP): Despite achieving record levels for full year production, sales volumes and revenue, the FY21
Corporate Scorecard was significantly impacted by constrained processing rates at the Orbost Gas Processing Plant (operated by APA Group).
Growth targets also fell short of those planned one year ago. Positive progress has been made on the Athena Gas Plant Project, the Company’s
Climate Active carbon neutral certification, the debt facility adjustment as well as being able to meet our gas customer nominations despite the
below expectation performance of the Orbost Gas Processing Plant. When considering overall company performance, the Board has assessed
the full FY21 Corporate Scorecard result as being 22/100.
This level of Corporate performance is considered by the Board to be below the threshold level for payment. The Board has therefore determined
that there will be no payment associated with the Company performance component of the STIP for the FY21 financial year for the Managing
Director, the Executive Leadership Team and for staff generally.
The Board has determined that individual performance components of the STIP will be paid. The Managing Director has, however, declined
to accept any STIP payment for FY21. The Board recognises and appreciates the leadership of the Managing Director in this regard. STIP
payments relating to FY21 individual performance are provided in section 4.6.3 of this report.
Directors’ Statutory Report
Directors Fees: There is to be no change to fees paid to Directors for FY22.
For the year ended 30 June 2021
The Company enters the new financial year in a sound position to materially grow the value of its portfolio. It is very pleasing to see Company
Directors Fees: There is to be no change to fees paid to Directors for FY22.
staff at all levels and locations committed to achieving improved outcomes for both the short and long term. I especially thank the Managing
The Company enters the new financial year in a sound position to materially grow the value of its portfolio. It is very
Director and the Executive Leadership Team not only for their commitment to achieve superior outcomes, but also their determination to work in a
pleasing to see Company staff at all levels and locations committed to achieving improved outcomes for both the short and
long term. I especially thank the Managing Director and the Executive Leadership Team not only for their commitment to
way that is consistent with the Cooper Energy Values.
achieve superior outcomes, but also their determination to work in a way that is consistent with the Cooper Energy Values.
Yours sincerely
Yours sincerely
Mr Jeffrey Schneider
Chairman of the People & Remuneration Committee
Mr Jeffrey Schneider
Chairman of the People & Remuneration Committee
55
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
4. Remuneration Report (audited) continued
Contents
4.1 Introduction
4.2 Key Management Personnel covered in this Report
4.3 Remuneration Governance
4.4 Nature & Structure of Executive KMP Remuneration
4.5 Cooper Energy’s Five-Year Performance and Link to Remuneration
4.6 2021 Executive KMP Performance and Remuneration Outcomes
4.7 Executive KMP Employment Contracts
4.8 2021 Remuneration Outcomes for Executive KMP
4.9 Nature of Non-Executive Director Remuneration
4.1 Introduction
Page
56
56
57
58
65
66
68
68
72
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.
The Report has been prepared in accordance with section 300A of the Corporations Act 2001 and unless specified otherwise, has been audited
in accordance with the provisions of section 308(3C) of the Corporations Act 2001.
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
• the executives on the Executive Leadership Team.
The Managing Director and 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:
Non-Executive Directors1
Mr J. Conde AO
Ms E. Donaghey
Mr H. Gordon
Mr J. Schneider
Ms V. Binns
Mr T. Bednall
Ms A. Williams2
Position
Chairman
Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director
Period KMP
1 July 2020 to 30 June 2021
1 July 2020 to 30 June 2021
1 July 2020 to 30 June 2021
1 July 2020 to 30 June 2021
1 July 2020 to 30 June 2021
1 July 2020 to 30 June 2021
1 July 2020 to 12 November 2020
1. Ms Giselle Collins has been appointed to the Board as a non-executive director, effective 19 August 2021 (subject to confirmation by
shareholders at the Company’s 2021 AGM). Ms Collins was therefore not a KMP of the Group during the reporting period.
2. Ms Williams stepped down from the Board effective 12 November 2020.
56
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited) continued
Executive KMP
Mr D. Maxwell
Mr A. Thomas
Ms V. Suttell1
Ms A. Jalleh
Mr I. MacDougall
Mr E. Glavas
Mr M. Jacobsen
Mr A. Haren2
Position
Managing Director
Period KMP
1 July 2020 to 30 June 2021
General Manager Exploration & Subsurface
1 July 2020 to 30 June 2021
Chief Financial Officer
1 July 2020 to 30 June 2021
Company Secretary & General Counsel
1 July 2020 to 30 June 2021
General Manager HSEC & Technical Services
1 July 2020 to 30 June 2021
General Manager Commercial & Development
1 July 2020 to 30 June 2021
General Manager Projects & Operations
1 July 2020 to 30 June 2021
General Manager People & Remuneration
18 January 2021 to 30 June 2021
1. Ms Suttell has tendered her resignation effective 30 September 2021.
2. Mr Haren was appointed to the role of General Manager People & Remuneration on 18 January 2021.
4.3 Remuneration Governance
4.3.1 Philosophy and objectives
The Company is committed to a remuneration philosophy that aligns to its business strategy and encourages superior performance and
shareholder returns. Cooper Energy’s approach towards remuneration aims to ensure that an appropriate balance is achieved among:
• 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, with a view to enhancing
Cooper Energy’s reputation and standing in the community.
Cooper Energy’s policy is to pay Fixed Annual Remuneration at the median level compared to resource industry benchmark data and supplement
this with “at risk” remuneration to bring total remuneration within the upper quartile when outstanding performance is achieved.
4.3.2 People & Remuneration Committee
The People & Remuneration Committee (which, as at the date of this report, is comprised of four Non-Executive Directors, all of whom are
independent) makes recommendations to the Board about remuneration strategies and policies for the Executive KMP and considers matters
related to organisational structure and operating model, company culture and values, diversity, succession for senior executives and executive
development and talent management. The ultimate responsibility for, and power to make company decisions with respect to these matters,
remains with the full Board.
On an annual basis, the People & Remuneration Committee makes recommendations to the Board about the form of payment and incentives to
Executive KMP and the amount. This is done with reference to Company performance and individual performance of the Executive KMP, relevant
employment market conditions, current industry practices and independent remuneration benchmark reports.
4.3.3 External remuneration advisers
The 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 reporting period and all remuneration benchmarking was
performed in-house against independent Australian resource industry remuneration data.
57
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited) continued
4.4 Nature & Structure of Executive KMP Remuneration
Executive KMP remuneration during the reporting period consisted of a mix of:
• Fixed Annual Remuneration (FAR);
• Short Term Incentive Plan (STIP) participation;
• Benefits such as accommodation, internet allowance and car parking; and
• Long Term Incentive Plan (LTIP) (composed of performance rights (PRs) and share appreciation rights (SARs) under the Company’s amended
Equity Incentive Plan approved by shareholders at the 2019 AGM).
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 cash reward) and rewarding
long-term sustainable performance (through the LTIP).
The Company’s remuneration profile for Executive KMP is as follows:
Managing Director
Remuneration Mix at Maximum
Performance (Super Stretch)
Other Executive KMP
Remuneration Mix at Maximum
Performance (Super Stretch)
33.33%
33.33%
31.8%
45.5%
33.33%
22.7%
Fixed Annual Remuneration
Short Term Incentive Plan
Long Term Incentive Plan
4.4.1 Remuneration strategy and framework – Linking Reward to Performance
The remuneration strategy sets the direction for the remuneration framework and drives the design and application of remuneration for the
Company, including Executive KMP.
The remuneration strategy:
• encourages a strong focus on financial and operational performance, and motivates Executive KMP to deliver sustainable business results
and returns to the Company’s shareholders over the short and long term;
• attracts, motivates and retains appropriately qualified and experienced talent; and
• aligns executive and shareholder interests through 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 significant changes to the key elements of the remuneration framework are anticipated in FY22.
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DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited) continued
4.4.2 Remuneration strategy and framework – Overview – FY2021
Performance Conditions
Remuneration Strategy/Performance Link
Fixed Annual
Remuneration
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
Short Term
Incentive Plan
(STIP)
Annual incentive
opportunity
delivered in cash
based on Company
and individual
performance
Strategy & Project Key Performance Indicators
(KPIs) (up to 40% of Company performance related
STIP award)
• Major Projects & Development
• Growth in Reserves & Resources
• Key Gas Strategy Milestones
• Acquisition and Divestment
Operational & Financial KPIs (up to 40% of
Company performance related STIP award)
• Production and Revenue
• Cost Management
• Process & Risk Management
• People and Stakeholder relationships
Safety & Sustainability KPIs (up to 20% of Company
performance related STIP award)
• Lead improvement objectives for environmental and
fatality prevention
• Sustainability and community relationships
• Total Recordable Case Frequency Rate
(TRCFR) target
Individual performance KPIs (up to 25% for
Managing Director & 30% for the other Executive KMP
of Final STIP award) aligned to strategic objectives.
Fixed Annual Remuneration is set to attract, retain
and motivate the right talent to deliver on the strategy
and contribute to the Company’s financial and
operational performance.
For executives new to their role, the aim is to set
Fixed Annual Remuneration 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.
STIP performance conditions are designed to support
the financial and strategic direction of the Company (the
achievement links to shareholder returns) and are clearly
defined and measurable.
A large proportion of outcomes are subject to the
Operational & Financial targets of the Company or
business unit, depending on the role of the executive
to ensure line of sight. Strategy & 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 Company’s Values.
Individual performance measures are agreed each
year. The individual measures relate to business unit
objectives, promotion of Company Values and identified
areas for development. This ensures a clear focus on
“how we work” i.e. our Values and culture, as well as
what we seek to achieve.
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DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited) continued
Long Term
Incentive Plan
(LTIP)
Three-year incentive
opportunity
delivered through
Performance
Rights (PRs) and
Share Appreciation
Rights (SARs)
Performance Conditions
Remuneration Strategy/Performance Link
LTIP is a mix of PRs and SARs. Maximum LTIP grant
is 100% of Fixed Annual Remuneration for Managing
Director and 70% of Fixed Annual Remuneration for
other Executive KMP.
Relative Total Shareholder Return is the only
performance condition. Relative Total Shareholder
Return 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.
• Relative Total Shareholder Return performance
is where there is sustained superior share price
performance of the Company compared to a Peer
Group of companies.
• 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.
Allocation of PRs & SARs upfront encourages executives
to ‘behave like shareholders’ from the grant date.
The PRs & 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 become 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 period).
Relative Total Shareholder Return is designed to
encourage executives to focus on the key performance
drivers which underpin sustainable growth in
shareholder value.
The Relative Total Shareholder Return 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 tougher than our industry peers.
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.
4.4.3 Fixed Annual Remuneration
Fixed Annual Remuneration includes base salary (paid in cash) and statutory superannuation. Executives are paid Fixed Annual Remuneration
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 Executive KMP Fixed Annual Remuneration against resource industry market surveys 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 Fixed Annual Remuneration.
4.4.4 Short Term Incentive 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 FY21 Company performance measures in the Company’s scorecard and
weightings are as follows:
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DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited) continued
Performance Measures
HSEC (20%)
• Health
Rationale
Targeting:
• Safety (Lost Time Injury, Total Recordable
• Leading HSEC performance
Incident Frequency Rate)
• Environment (reportable environmental
incidents)
• Community (strategy, grievance
management)
• HSEC Management System
• Efficient processes (cost & time), easily understood
• Cooper Energy team clearly engaged & continually improving
• Leading emissions management, clear sustainability
positioning and policy
Production &
Revenue (20%)
• Production MMboe
• Revenue A$ million
Targeting growing value by increasing production & margin from
existing permits
• Gas marketing $/GJ average spot and new
sales prices
• Cash margin A$/boe (sales revenue less
cash operating costs (excludes DD&A))
Project Delivery
(20%)
• Schedule
• Cost
Targeting:
• Major capital projects delivered per scope, within schedule
• Front End Engineering & Design and Final
and budget, with appropriate contingency included
Investment Decisions
• Clear management systems
• Consistent successful major project delivery
Growth (20%)
• Reserves
• Gas marketing
Targeting:
• Development projects per schedule and adding economic
• Acquisitions & divestments
value
(in each case to reflect a growing business)
• Term gas contracts that underpin new business and add value
People, Culture &
Enablers (20%)
• Cost Management
• Funding
• Processes and Risk Management
• People
• Stakeholder Relationships
Please note as follows:
“HSEC” means Health Safety Environment & Community
“MMboe” means Million barrels of oil equivalent
“GJ” means Gigajoule
“DD&A” means Depreciation, Depletion & Amortisation
• Maximising value through portfolio management and
acquisitions and divestment
• Leveraging competitive strengths
• Building growth
Targeting:
• “One team” performance
• Applying the Cooper Energy Values and culture to deliver
our strategy
• Tight cost management, accurate forecasting
• Funding fit for purpose, creating shareholder value and
being optimised
• Efficient, cost-effective management and IT systems helping
to make jobs easier
• Stakeholder relationships creating value
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DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited) continued
The key features of the STIP for FY21 are as follows:
STIP FY21 Plan Feature
Details
What is the purpose of the STIP?
The STIP is designed to motivate and reward Executive KMP 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 Executive KMP to achieve
operational and business milestones in a balanced and sustainable manner.
What is the vehicle of the STIP award?
The STIP award is delivered in the form of a cash payment, usually in October.
Managing Director
Other Executive KMP
100%
50%
Each year, the Board reviews and approves the performance criteria for the year ahead by
approving a Company scorecard and individual performance contracts are agreed with each
Executive KMP. The Company’s STIP operates over a 12-month performance period from
1 July to 30 June.
The measurement of Company performance is based on the achievement of key performance
indicators (KPIs) set out in a Company scorecard. See section 4.6.2 for the Company scorecard
measures used for FY21. 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 – 75% Company: 25% individual
• Executives – 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.
Individual performance measures are agreed each year. The individual measures relate to
business unit objectives, promotion of Company Values and identified areas for development.
This ensures a clear focus on “how we work” i.e. our values and culture, as well as what we seek
to achieve.
In FY21 the Managing Director’s individual performance measures included; leading standards
relating to HSEC, maintaining constructive stakeholder relationships, effective leadership of
the executive leadership team, and enhancement of the ‘one team’ ethos and company values.
Other measures included ensuring funding plans are in place to support activity plans, the
development of management systems, and strategy development activity aimed at creating
future value growth.
What is the maximum award
opportunity (% of Fixed
Remuneration)?
What is the performance period?
How are the performance
measures determined and what are
their relative weightings?
What elements are included
in the individual’s personal
performance measures?
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DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited) continued
4.4.5 Long Term Incentive Plan (LTIP) - Overview
In the reporting period, the LTIP involved grants of Performance Rights (PRs) and Share Appreciation Rights (SARs) under the Equity Incentive
Plan. The key features of the grants made in the 2021 financial year (granted December 2020) are set out in the following table:
FY21 LTIP Plan Feature
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 for employees (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 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 annual LTIP
grant (% of Fixed Remuneration)?
Managing Director
Executive KMP
Senior staff
100%
70%
50%
What is the LTIP performance period?
The performance period is three years.
What are the performance measures?
Grants in years prior to the 2019 financial year allowed for re-testing 12 months following the end
of the performance period. A re-test was considered appropriate because the Company’s growth
had been dependent on development of projects that have generally taken greater than three
years from conception to start-up. Given the growth of the Company, including its development
activities, the Company will no longer be reliant on single projects. As a consequence, the Board
determined that re-testing would not form part of the terms of the Incentives for future grants.
Re-testing is not a feature of the Equity Incentive Plan approved by shareholders at the 2019
Annual General Meeting.
100% of the grant (both PRs and SARs) is subject to a Relative Total Shareholder Return
performance measure. Relative Total Shareholder Return 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 Relative Total Shareholder Return 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 comparator group of
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.
63
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited) continued
FY21 LTIP Plan Feature
Details
Which companies make up the
Relative TSR peer group?
What happens on cessation of
employment?
The Relative Total Shareholder Return of the Company is measured as a percentile ranking
compared to the following comparator Group of 12 listed entities: Woodside Petroleum Limited;
Oil Search Limited; Santos Limited; Beach Energy Limited; Senex Energy Limited; Karoon Gas
Australia Limited; FAR Limited; Central Petroleum Limited; Buru Energy Limited; Carnarvon
Petroleum Limited; Strike Energy Limited; Horizon Oil Limited.
The peer group was based on a group of ASX-listed companies in the oil and gas sector,
with a range of market capitalisation.
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 a discretion to determine that some
or all awards may be retained upon cessation of employment.
What happens if there is a change
of control?
In the event of a change of control, unless the Board determines otherwise, pro-rata vesting will
occur on the basis of the proportion of the relevant performance period that has elapsed.
Who can participate in the LTIP?
Eligibility is generally restricted to Executive KMP and other senior staff who are in a position to
influence shareholder value the most.
Is there a cap on dilution?
5% total on issue (excluding KMP).
Will the Company make any changes
to the LTIP for the grant to be made in
the 2022 financial year?
It is not anticipated that the general structure of the LTIP will change for grants made in FY22.
In FY21, a review was undertaken which included the appropriateness of Relative Total
Shareholder Return (RTSR) being the sole measure for LTIP vesting. It was determined
that RTSR remained a common performance measure within the oil and gas sector and an
appropriate measure as the Company transitions from development to gas production. As part
of this review, it was also acknowledged that SARs by their nature, have a natural Absolute
Total Shareholder Return measure whereby no SARs will be exercisable unless the share price
appreciates over the measurement period.
The Relative TSR peer group is reviewed prior to each grant to reflect changes including merger
and acquisitions within the group. The peer group in FY22 will remained based on a group of
ASX-listed companies in the oil and gas sector, with a range of market capitalisation.
4.5 Cooper Energy’s Five-Year Performance and Link to Remuneration
The following graphs illustrated the five-year performance and links to the remuneration strategy and framework:
Annual Production (MMboe)
Proved & Probable Reserves (MMboe)
1.49
1.31
1.50
0.96
2.63
FY17
FY18
FY19
FY20
FY21
Links directly to Company STIP reward outcomes as an
Operational & Financial KPI.
52.4
52.7
49.9
47.1
11.7
FY17
FY18
FY19
FY20
FY21
Links directly to Company STIP reward outcome as a Growth KPI.
Total Recordable Incident Frequency Rate
(events per hours worked, where a lower value is better)
Sales Revenue ($ million)
64
6.92
131.7
4.07
3.53
1.98
0.0
67.5
75.5
78.1
39.1
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
Links directly to Company STIP reward outcome as a
Links directly to Company STIP reward outcome as an
Safety & Sustainability KPI.
Operational & Financial KPI.
Financial – Profit After Tax ($ million)
Financial – Earnings Per Share (cents)
27.0
1.8
-12.3
-12.1
-30.0
-1.8
-0.7
-5.3
-1.8
-86.0
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
Links directly to Company STIP reward outcome as an
Operational & Financial KPI through cost management.
Links directly to Company LTIP reward outcome by increasing
shareholder value.
Financial – Total Shareholder Return (%)
Share Price – As at 30 June ($ per share)
72.7
6.0
40.3
-30.6
-30.7
0.38
0.39
0.38
0.54
0.26
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
Links directly to Company LTIP reward outcome by increasing
Links directly to Company LTIP reward outcome by increasing
shareholder value.
shareholder value compared to peers.
Market Capitalisation – As at 30 June ($ million)
875.6
616.4
610.0
433.4
424.1
FY17
FY18
FY19
FY20
FY21
Links directly to Company LTIP reward outcome by increasing
shareholder value compared to peers.
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Annual Production (MMboe)
Proved & Probable Reserves (MMboe)
1.49
1.31
1.50
0.96
2.63
FY17
FY18
FY19
FY20
FY21
Links directly to Company STIP reward outcomes as an
Operational & Financial KPI.
4. Remuneration Report (audited) continued
52.4
52.7
49.9
47.1
11.7
FY17
FY18
FY19
FY20
FY21
Links directly to Company STIP reward outcome as a Growth KPI.
Total Recordable Incident Frequency Rate
(events per hours worked, where a lower value is better)
Sales Revenue ($ million)
4.07
3.53
1.98
0.0
6.92
131.7
67.5
75.5
78.1
39.1
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
Links directly to Company STIP reward outcome as a
Safety & Sustainability KPI.
Links directly to Company STIP reward outcome as an
Operational & Financial KPI.
Financial – Profit After Tax ($ million)
Financial – Earnings Per Share (cents)
27.0
1.8
-12.3
-12.1
-30.0
-1.8
-0.7
-5.3
-1.8
-86.0
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
Links directly to Company STIP reward outcome as an
Operational & Financial KPI through cost management.
Links directly to Company LTIP reward outcome by increasing
shareholder value.
Financial – Total Shareholder Return (%)
Share Price – As at 30 June ($ per share)
72.7
6.0
40.3
-30.6
-30.7
0.38
0.39
0.38
0.54
0.26
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
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
616.4
610.0
433.4
424.1
FY17
FY18
FY19
FY20
FY21
Links directly to Company LTIP reward outcome by increasing
shareholder value compared to peers.
In FY21 and in the past five years, dividends were not paid by the Company to its shareholders, nor was there a return of capital by the
Company to its shareholders.
65
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited) continued
4.6 2021 Executive KMP Performance and Remuneration Outcomes
4.6.1 Fixed Annual Remuneration outcome
Following a review by the Board at the end of FY21, there will be no increases to Base Salary for the Managing Director or the Executive
Leadership Team except for three Executive Leadership Team members who have increased job responsibilities. Their base salary increases
range from 2.24% to 3.56%. Such increases are consistent with benchmarking data within the resources industry.
Fixed Annual Remuneration will be adjusted as a consequence of increases to statutory superannuation contribution effective 1 July 2021.
This has been applied to the Managing Director and Executive Leadership Team.
4.6.2 STIP performance outcomes – Company Results
The Company Scorecard results for the reporting period ranged between below Threshold and Target and cover the full FY21. The Company’s
FY21 result was a score of 22 out of 100.
Company Scorecard Results FY21
Threshold
Target
Stretch
Super
Stretch
Performance Measure Outcome
No LTIs or reportable environmental incidents.
TRIFR 6.92. Carbon Neutral certification achieved.
Community engagement positive and supporting projects.
No COVID-19 incidents. Assessed Score: 12/20
Production of 2.63 MMboe v 3.87 MMboe.
Assessed Score: 0/20
OGPP delayed. Athena Gas Plant at P50.
OP3D not in FEED. Assessed Score: 0/20
Started Sole GSAs and back up supply in place.
No reserve growth or material acquisition or divestment.
Assessed Score: 0/20
Adjusted funding arrangements. Effective cost
management. Positive staff engagement as measured
by staff survey. Improved risk management, processes
and management systems. Sustained high level of
stakeholder engagement. Assessed Score: 10/20
Performance
Measure
(Weighting %)
HSEC (20%)
Production &
Revenue (20%)
Project Delivery
(20%)
Growth (20%)
People, Culture &
Enablers (20%)
FY21 Performance:
66
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited) continued
4.6.3 STIP performance outcomes – Individual Results
In light of the Company’s performance in the year ending 30 June 2021, the Board has determined that no STIP payment relating to
Company performance will be awarded to the Managing Director or Executive KMP. Figures in this table reflect amounts relating to individual
performance only.
Short Term Incentive (STI) for the year ended 30 June 2021
Executive KMP
Mr D. Maxwell ¹
Mr A. Thomas
Ms V. Suttell ²
Ms A. Jalleh
Mr I. MacDougall
Mr E. Glavas
Mr M. Jacobsen
Mr A. Haren³
STI target
% of Fixed Annual
Remuneration
STI maximum
% of Fixed Annual
Remuneration
50%
25%
25%
25%
25%
25%
25%
25%
100%
50%
50%
50%
50%
50%
50%
50%
Cash STI
$
0
40,361
41,220
47,678
35,535
36,497
35,535
12,526
% earned of
maximum STI
opportunity
% forfeited of
maximum STI
opportunity
0%
17%
17%
24%
15%
17%
15%
8%
100%
83%
83%
76%
85%
83%
85%
92%
1. Managing Director, Mr Maxwell declined to accept any payment of STIP for the 2021 financial year (refer below).
2. Ms Suttell has tendered her resignation effective 30 September 2021.
3. Mr Haren commenced as an Executive KMP on 18 January 2021. His entitlement is prorated.
The Board determined an individual performance achievement level of 83% for Mr Maxwell, Managing Director. As a result, Mr Maxwell was
eligible for a Cash STI payment of 21% of his maximum STI opportunity. However, Mr Maxwell has declined to accept any STI payment for FY21.
The Board recognises and appreciates the leadership of the Managing Director in this regard.
4.6.4 LTIP Outcome
The Company’s Relative Total Shareholder Return compared to the peer group is set out below for the LTIP grant that vested in December 2020.
The base for the graph is December 2017, being the grant date of PRs and SARs that were made under the Company’s Equity Incentive Plan.
The terms of the Equity Incentive Plan are set out in section 4.4.5.
Share Price Performance of Cooper Energy Limited Versus Applicable Peer Group
8 December 2017 to 7 December 2020
-100%
-50%
0%
50%
100%
150%
200%
250%
300%
350%
400%
Cooper Energy Limited
19%
162%
338%
64%
33%
-3%
-11%
-24%
-31%
-44%
-59%
-68%
The value of LTIP that vested in December 2020 decreased compared to December 2019. The vesting of this award in December 2020 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 8 December 2017 to 7 December 2020, Cooper Energy’s total shareholder return was 19% and
it achieved a Relative Total Shareholder Return percentile rank of 57%. This resulted in a vesting outcome of 42% of all performance rights and
SARs that were granted in December 2017.
67
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited) continued
Grants in years prior to the 2019 financial year allowed for re-testing 12 months following the end of the performance period. In FY21 grants from
8 December 2016 that vested on 7 December 2019 were subject to re-testing on 7 December 2020. However, the percentile rank was below the
50th percentile and therefore no shares vested as a result of this re-testing.
4.7 Executive KMP Employment Contracts
Each KMP has an ongoing employment contract. All 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.
The entitlements upon termination of the Managing Director and other Executive KMP’s have not changed between 2020 and 2021.
Key terms for each Executive KMP are set out below:
Executive KMP Notice by
Cooper Energy
Notice by
Executive KMP
Indemnity
Agreement
Treatment on Termination
by Cooper Energy
David Maxwell
12 months
6 months
Other Executive
KMP
6 months
3 months
Company provides
Indemnity Agreement,
Directors and Officers
indemnity insurance
and access to
Company records.
Where the Managing Director is not employed for the full period
of notice a payment in lieu may be made. A payment in lieu
of notice is based on Fixed Remuneration (base salary and
superannuation). Upon termination, superannuation is not paid
on accrued annual leave or long service leave. Unused personal
leave is not paid out and is forfeited.
Company provides
Indemnity Agreement,
Directors and Officers
indemnity insurance
and access to
Company records.
Where an Executive KMP is not employed for the full period
of notice a payment in lieu may be made. 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.
4.8 2021 Remuneration Outcomes for Executive KMP
4.8.1 Remuneration realised by Executive KMP in 2021 and 2020 (not audited)
The Company believes that reporting remuneration realised by Executive KMP is useful to shareholders and provides clear and transparent
disclosure of remuneration provided by the Company. The tables set out below show amounts paid to Executive KMP and the cash value of
equity awards which vested during the reporting period.
This information is non-IFRS 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 and the tables in sections 4.8.2 and 4.9.3. The information in this section 4.8.1 is not audited.
The total benefits actually delivered during the reporting period and set out in the table below comprise the following elements:
• Fixed Annual Remuneration is base salary and superannuation (statutory and salary sacrifice);
• STIP cash payment made in October each year. The STIP paid in October 2020 (FY2021) is included in the 2021 figure. The STIP paid in
October 2019 (FY2020) is included in the 2020 figure;
• LTIP realised based on the market value of PRs and SARs that vested in December 2019 & 2020 (granted in December 2016 & 2017
respectively); and
• “Other” is the value of benefits including fringe benefits tax on accommodation, car parking and other benefits.
Executive KMP
Year
Fixed Annual
Remuneration1
$
2021
2020
2021
2020
2021
2020
2021
2020
915,000
905,247
470,000
463,250
480,000
472,500
390,000
347,532
Mr D. Maxwell
Mr A. Thomas
Ms V. Suttell
Ms A. Jalleh²
68
STIP1
$
439,200
614,363
108,570
148,793
110,880
161,743
87,210
-
LTIP1
$
347,704
801,800
106,484
286,646
103,948
-
-
-
Other
$
29,231
74,755
6,011
6,515
6,011
6,515
6,011
35,535
Total
$
1,731,135
2,396,165
691,065
905,204
700,839
640,758
483,221
383,067
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
4. Remuneration Report (audited) continued
Executive KMP
Year
Fixed Annual
Remuneration1
$
Mr I. MacDougall
Mr E. Glavas
Mr M. Jacobsen
Mr A. Haren3
2021
2020
2021
2020
2021
2020
2021
2020
460,000
453,750
425,000
417,500
460,000
453,750
134,019
-
STIP1
$
98,325
131,075
98,175
132,671
102,293
121,721
-
-
LTIP1
$
106,484
274,891
95,075
204,299
106,484
-
-
-
Other
$
6,011
6,515
6,011
6,515
508
536
196
-
Total
$
670,820
866,231
624,261
760,985
669,285
576,007
134,215
-
1. Amounts above include adjustments for unpaid leave where applicable.
2. Ms Jalleh commenced as an Executive KMP on 9 August 2019 and her entitlements for 2020 are prorated.
3. Mr Haren commenced as an Executive KMP on 18 January 2021 and his entitlements for 2021 are prorated.
4.8.2 Table of Executive KMP Statutory Remuneration Disclosure for 2021 and 2020 financial years
Benefits
Short-term
Long-term
Post
Employment(c)
Share Based
Remuneration(e)
Base Salary
STIP (a)
Executive KMP
$
Mr D. Maxwell
2021
893,306
$
-
Other
Short-term
Benefits(b)
$
Long
Service
Leave
$
29,231
23,293
2020
884,245
510,298
74,755
17,601
Mr A. Thomas
2021
448,306
40,361
6,011
11,618
2020
442,247
123,270
6,515
16,993
Ms V. Suttell
2021
458,306
41,220
6,011
12,591
Ms A. Jalleh(f)
2020
2021
2020
451,497
136,412
6,515
35,691
368,306
47,678
6,011
328,279
87,210
35,535
-
-
Mr I. MacDougall
2021
438,306
35,535
6,011
11,601
Mr E. Glavas
2020
2021
2020
432,747
97,729
6,515
10,572
403,306
36,497
6,011
10,653
396,497
111,282
6,515
5,257
Mr M. Jacobsen
2021
438,306
35,535
2020
432,747
92,343
508
536
-15,211
17,017
Mr A. Haren(g)
2021
123,367
12,526
196
2020
-
-
-
-
-
Superannuation(d)
LTIP
Total
$
21,694
21,003
21,694
21,003
21,694
21,003
21,694
19,252
21,694
21,003
21,694
21,003
21,694
21,003
10,652
-
$
$
739,698
1,707,222
762,633
2,270,535
259,730
787,720
258,707
868,735
263,153
802,975
219,540
870,658
116,690
560,379
41,231
511,507
255,246
768,393
254,572
823,138
233,449
711,610
224,387
764,941
255,246
736,078
216,800
780,446
-
-
146,741
-
a) The STIP values noted for 2020 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 FY21 which will be paid in FY22.
b)
Other short-term benefits include fringe benefits on accommodation, car parking 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 FY21.
69
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
4. Remuneration Report (audited) continued
c) Superannuation is the only applicable post-employment benefit ie. no pension or similar benefits for Executive KMP.
d) Superannuation includes the amounts required to be contributed by the Company and does not include amounts salary sacrificed.
e)
In accordance with the requirements of the Accounting Standards, remuneration includes a proportion of the value of the equity-linked
compensation determined as at the grant date of the PRs and progressively expensed over the vesting period. The amount allocated as
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 27 of the Notes to the Financial Statements.
f) Ms Jalleh commenced as an Executive KMP on 9 August 2019 and her entitlements for 2020 are prorated.
g) Mr Haren commenced as an Executive KMP on 18 January 2021 and his entitlements for 2021 are prorated.
No cash-settled share-based payment transactions or other forms of share-based payment compensation (including hybrids) were made
by the Company.
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 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 Equity Incentive Plan on 10 December
2020. The PRs and SARs were granted for no consideration and the employee received no cash benefit at the time of receiving the rights. The
cash benefit will be received by the employee following the sale of the resultant shares, which can only be achieved after the rights have been
vested and the shares are issued.
PRs and SARs granted under the Equity Incentive Plan were valued by an independent consultant who applied the Monte Carlo simulation model
to determine the probability of achievement of the Relative Total Shareholder Return against performance conditions.
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)
Fair value
of rights at
grant date
No. of
rights vested
during period
% of rights
vested to
30 June
2021
No. of rights
granted
during
period
Share Appreciation Rights
(Equity Incentive Plan)
Fair value
of rights at
grant date
No. of
rights vested
during period
% of rights
vested to
30 June
2021
No. of rights
granted
during
period
Directors
Mr D. Maxwell
1,310,888
335,587
689,529
43%
4,197,247
457,500
1,731,761
41%
Executive KMP
Mr A. Thomas
471,346
120,665
211,168
Ms V. Suttell
481,375
123,232
206,140
Ms A. Jalleh
391,117
100,126
-
Mr I. MacDougall
461,318
118,097
211,168
Mr E. Glavas
426,217
109,112
188,543
Mr M. Jacobsen
461,318
118,097
211,168
Mr A. Haren¹
-
-
-
1. Mr Haren commenced as an Executive KMP on 18 January 2021.
43%
13%
0%
43%
39%
13%
0%
1,509,174
164,500
530,351
1,541,284
168,000
517,724
1,252,293
136,500
-
1,477,064
161,000
530,351
1,364,678
148,750
473,528
1,477,064
161,000
530,351
-
-
-
41%
11%
0%
41%
37%
11%
0%
The vesting date of the PRs granted on 10 December 2020 is 10 December 2023. The fair value of these rights is $0.256 per right and the share
price on grant date was $0.39. The performance period for these PRs commenced on 10 December 2020.
The vesting date of the SARs granted on 10 December 2020 is 10 December 2023. The fair value of these rights is $0.109 per right and the
share price on grant date was $0.39. The performance period for these SARs commenced on 10 December 2020.
70
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
4. Remuneration Report (audited) continued
4.8.4 Movement in Incentive Rights
The movement during the reporting period in the number of Performance Rights (PRs) granted but not exercisable over ordinary shares in
Cooper Energy held, directly, indirectly or beneficially, by each KMP, including their related parties, is as follows:
Performance Rights
(Equity Incentive Plan)
Held at
1 July 2020
Granted
Lapsed
Vested &
Exercised
Held at
30 June 2021
Directors
Mr D. Maxwell1
Mr H. Gordon2
Executive KMP
Mr A. Thomas
Ms V. Suttell
Ms A. Jalleh
Mr I. MacDougall
Mr E. Glavas
Mr M. Jacobsen
Mr A. Haren³
3,989,401
180,683
1,347,249
1,123,912
228,260
1,325,895
1,165,599
1,112,131
-
1,310,888
-
471,346
481,375
391,117
461,318
426,217
461,318
-
623,503
180,683
222,905
-
-
213,764
158,869
-
-
689,529
3,987,257
-
-
211,168
206,140
-
211,168
188,543
211,168
-
1,384,522
1,399,147
619,377
1,362,281
1,244,404
1,362,281
-
1. As a consequence of the Equity Incentive Plan amendments approved by shareholders at the Company’s Annual General Meeting held
on 7 November 2019 (see note below), the terms of the PRs held by Mr Maxwell at 1 July 2019 were also amended.
2. PRs were granted to Mr Gordon when he was an Executive Director.
3. Mr Haren commenced as an Executive KMP on 18 January 2021.
The terms of the PRs held at 1 July 2019 were amended following shareholder approval at the Company’s Annual General Meeting held on
7 November 2019 to provide that “good leavers” would retain rights held upon cessation of employment, subject to a Board discretion to
determine otherwise. Rights were also amended to provide for pro-rata vesting of rights upon a change of control event on the basis of the
proportion of the relevant performance period that has elapsed.
The movement during the reporting period in the number of Share Appreciation Rights (SARs) granted but not exercisable over ordinary shares
in Cooper Energy held, directly, indirectly or beneficially, by each KMP, including their related parties, is as follows:
Share Appreciation Rights
(Equity Incentive Plan)
Held at
1 July 2020
Granted
Lapsed
Vested &
Exercised⁴
Held at
30 June 2021
Directors
Mr D. Maxwell¹
Mr H. Gordon²
Executive KMP
Mr A. Thomas
Ms V. Suttell
Ms A. Jalleh
Mr I. MacDougall
Mr E. Glavas
Mr M. Jacobsen
Mr A. Haren³
11,044,509
466,672
3,752,327
3,182,631
797,387
3,690,768
3,256,857
3,138,654
-
4,197,247
-
1,509,174
1,541,284
1,252,293
1,477,064
1,364,678
1,477,064
-
1,610,399
466,672
1,731,761
11,899,596
-
-
575,723
-
-
552,114
410,330
-
-
530,351
517,724
-
530,351
473,528
530,351
-
4,155,427
4,206,191
2,049,680
4,085,367
3,737,677
4,085,367
-
1. As a consequence of the Equity Incentive Plan amendments approved by shareholders at the Company’s Annual General Meeting held
on 7 November 2019 (see note below), the terms of the SARs held by Mr Maxwell at 1 July 2019 were also amended.
2. SARs were granted to Mr Gordon when he was an Executive Director.
3. Mr Haren commenced as an Executive KMP on 18 January 2021.
4. 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.
71
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited) continued
The terms of the SARs held at 1 July 2019 were amended following shareholder approval at the Company’s Annual General Meeting held on
7 November 2019 to provide that “good leavers” would retain rights held upon cessation of employment, subject to a Board discretion to
determine otherwise. Rights were also amended to provide for pro-rata vesting of rights upon a change of control event on the basis of the
proportion of the relevant performance period that has elapsed.
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:
Role
Chairman*
Member
Board
Audit
Committee
Risk &
Sustainability
Committee
People &
Remuneration
Committee
Governance &
Nomination
Committee
$240,000
$115,000
$20,000
$10,000
$20,000
$10,000
$20,000
$10,000
$0
$5,000
*Where the Chairman of the Board is a member of a committee, he will not receive any additional committee fees.
In August 2021, the role of the Nomination Committee has been expanded to incorporate governance, and therefore the Committee has been
renamed the Governance & Nomination Committee. Annual fees for this Committee will be brought into line with the other Committees effective
August 2021.
Remuneration paid to the Non-Executive Directors for the reporting period and for the previous reporting period is shown in the table in
Section 4.9.3.
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.
Note that Ms Alice Williams stepped down from the Board effective 12 November 2020, and Ms Giselle Collins has been appointed to the Board
as a non-executive director, effective 19 August 2021 (subject to confirmation by shareholders at the Company’s 2021 AGM).
72
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited) continued
4.9.2 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:
Directors¹
Mr J. Conde AO
Mr D. Maxwell
Ms E. Donaghey
Mr H. Gordon
Mr J. Schneider
Ms V. Binns
Mr T. Bednall
Executive KMP
Mr A. Thomas
Ms V. Suttell²
Ms A. Jalleh
Mr I. MacDougall
Mr E. Glavas
Mr M. Jacobsen
Mr A. Haren³
Held at
1 July 2020
Purchases
859,093
18,874,365
160,000
3,096,138
1,016,594
-
44,499
4,850,025
40,600
-
3,176,844
2,083,772
-
-
-
155,000
420,000
-
-
322,857
88,000
-
42,000
-
-
-
-
-
Received on
vesting of
PRs & SARs
-
970,721
-
-
-
-
-
297,283
290,204
-
297,283
265,431
297,283
-
Sales
Held at
30 June 2021
-
-
-
1,350,000
-
-
-
-
-
-
-
925,000
-
-
859,093
20,000,086
580,000
1,746,138
1,016,594
322,857
132,499
5,147,308
372,804
-
3,474,127
1,424,203
297,283
-
1. Ms Williams stepped down from the Board effective 12 November 2020.
2.
3. Mr Haren commenced as an Executive KMP on 18 January 2021.
In FY21 Ms Suttell became a trustee of a superannuation fund that holds 42,000 shares and is one of the potential beneficiaries of that trust.
Options
No options were issued (or forfeited) during the year.
73
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Remuneration Report (audited) continued
4.9.3 Table of Directors’ remuneration for 2021 and 2020 financial years
Benefits
Short-term
Base Salary
& Fees
STIP(a)
Other
Short-term
Benefits(b)
Long
Term
Long
Service
Leave
$
-
-
$
-
-
$
-
-
-
29,231
23,293
884,245
510,298
74,755
17,601
Directors
$
Mr J. Conde AO
2021
219,178
Mr D. Maxwell
2020
2021
2020
219,178
893,306
Ms E. Donaghey 2021
131,659
2020
137,131
Mr H. Gordon(e)
2021
132,420
2020
136,225
Mr J. Schneider
2021
136,986
Ms V. Binns(f)
Mr T. Bednall(f)
2020
2021
2020
2021
2020
Ms A. Williams(g)
2021
136,986
138,204
40,335
130,137
30,863
48,724
2020
136,225
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Post
Employment
Share Based
Remuneration(d)
Superannuation(c)
LTIP
Total
$
20,822
20,822
21,694
21,003
12,508
13,027
12,580
12,941
13,014
13,014
13,129
3,832
12,363
2,932
4,629
12,941
$
-
-
$
240,000
240,000
739,698
1,707,222
762,633
2,270,535
-
-
-
144,167
150,158
145,000
31,926
181,092
-
-
-
-
-
-
-
-
150,000
150,000
151,333
44,167
142,500
33,795
53,353
149,166
a) The STIP values noted for 2020 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 FY21 which will be paid in FY22.
b) Other short-term benefits include fringe benefits on accommodation, car parking and other benefits.
c) Superannuation includes the amounts required to be contributed by the Company and does not include amounts salary sacrificed.
d)
In accordance with the requirements of the Accounting Standards, remuneration includes a proportion of the value of the equity-linked
compensation determined as at the grant date of the PRs and progressively expensed over the vesting period. The amount allocated as
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.
e) The LTIP value noted for 2020 relates to PRs and SARs which were granted to Mr Gordon when he was an Executive Director.
f) Ms Binns and Mr Bednall were each appointed to casual vacancies as Non-Executive Directors in March 2020. In each case their
remuneration for 2020 has been prorated.
g) Ms Williams stepped down from the Board effective 12 November 2020.
End of remuneration report.
74
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 5. Principal activities
Cooper Energy is an upstream oil and gas 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 production, exploration and development licences or permits. In most cases, the licence or permit terms
specify the environmental regulations applicable to oil and gas 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 Shares1
Performance Rights
Share Appreciation Rights
Mr J. Conde AO
Mr D. Maxwell
Mr T. Bednall
Ms V. Binns
Ms E. Donaghey
Mr H. Gordon
Mr J. Schneider
Ms A. Williams2
859,093
20,000,086
132,499
322,857
580,000
1,746,138
1,016,594
Nil
3,987,257
Nil
11,899,596
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
1.
Ms Giselle Collins has been appointed to the Board as a non-executive director, effective 19 August 2021 (subject to confirmation by
shareholders at the Company’s 2021 AGM). Ms Collins was therefore not a Director during the reporting period.
2. Ms Williams stepped down from the Board effective 12 November 2020.
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 20,919,555 outstanding PRs and 57,433,406 SARs under the Equity Incentive Plan approved by shareholders
at the 2019 AGM.
During the financial year 4,378,707 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 2021.
12. Events after financial reporting date
Refer to Note 30 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.
75
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Directors’ Statutory Report
For the year ended 30 June 2021
14. Indemnification and insurance of directors and officers
Indemnification and insurance of directors and officers
12.
14.1 Indemnification
Indemnification
14.1
The parent entity has agreed to indemnify the current Directors and Officers, and past Directors and Officers, of the parent entity and its
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
subsidiaries, where applicable, against all liabilities (subject to certain limited exclusions) to persons (other than the parent entity and its
than the parent entity and its subsidiaries) which arise out of the performance of their normal duties as a Director or
subsidiaries) which arise out of the performance of their normal duties as a Director or Officer, unless the liability relates to conduct involving
Officer, unless the liability relates to conduct involving a lack of good faith. The parent entity has agreed to indemnify the
a lack of good faith. The parent entity has agreed to indemnify the Directors and Officers against all costs and expenses (other than certain
Directors and Officers against all costs and expenses (other than certain excluded legal costs) incurred in defending an
excluded legal costs) incurred in defending an action that falls within the scope of the indemnity and any resulting payments.
action that falls within the scope of the indemnity and any resulting payments.
14.2 Insurance premiums
Insurance premiums
12.2
During the financial year, the parent entity has paid insurance premiums in respect of Directors’ and Officers’ liability and
During the financial year, the parent entity has paid insurance premiums in respect of Directors’ and Officers’ liability and legal insurance
legal insurance contracts for current and former Directors and Officers of the parent entity. The insurance contracts relate
contracts for current and former Directors and Officers of the parent entity. The insurance contracts relate to costs and expenses incurred by
to costs and expenses incurred by the relevant Directors and Officers in defending proceedings, whether civil or criminal
the relevant Directors and Officers in defending proceedings, whether civil or criminal and whatever their outcome and other liabilities that may
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
arise from their position, with exceptions including conduct involving a wilful breach of duty or improper use of information or position to gain a
contracts outlined above do not contain details of premiums paid in respect of individual Directors or Officers of the parent
personal advantage. The insurance contracts outlined above do not contain details of premiums paid in respect of individual Directors or Officers
entity.
of the parent entity.
Indemnification of auditors
13.
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
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
its audit engagement agreement against claims by third parties arising from the audit (for an unspecified amount) except
agreement against claims by third parties arising from the audit (for an unspecified amount) except in the case where the claim arises because
in the case where the claim arises because of Ernst & Young's negligent, wrongful or wilful acts or omissions. No payment
of Ernst & Young's negligent, wrongful or wilful acts or omissions. No payment has been made to indemnify Ernst & Young during or since the
has been made to indemnify Ernst & Young during or since the financial year.
financial year.
14. Auditor’s independence declaration
16. Auditor’s independence declaration
The auditor’s independence declaration is set out on page 90 and forms part of the Directors’ report for the financial year
ended 30 June 2021.
The auditor’s independence declaration is set out on page 90 and forms part of the Directors’ report for the financial year ended 30 June 2021.
15. Non-audit services
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
The amounts paid and payable to the auditor of the Group, Ernst & Young and its related practices for non-audit services provided during the
provided during the year was $48,300 (2020: $187,915). The directors are satisfied that the provision of non-audit services
year was $48,300 (2020: $187,915). The directors are satisfied that the provision of non-audit services is compatible with the general standard of
is compatible with the general standard of independence for auditors imposed by the Corporations Act 2001. The nature
independence for auditors imposed by the Corporations Act 2001. The nature and scope of each type of non-audit service provided means that
and scope of each type of non-audit service provided means that auditor independence was not compromised.
auditor independence was not compromised.
16. Rounding
18. 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
The Group is of a kind referred to in ASIC Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191 dated 24 March 2016
rounded to the nearest thousand dollars, unless otherwise stated.
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.
This report is made in accordance with a resolution of the Directors.
Mr John C. Conde AO
Mr John C. Conde AO
Chairman
Chairman
Dated at Adelaide 23 August 2021
Dated at Adelaide 23 August 2021
Mr David P. Maxwell
Managing Director
Mr David P. Maxwell
Managing Director
76
DIRECTORS’ STATUTORY REPORTFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
Cooper Energy Limited
and its controlled entities
FINANCIAL
STATEMENTS
For the year ended 30 June 2021
77
COOPER ENERGY ANNUAL REPORT 2021 CONSOLIDATED STATEMENT OF
COMPREHENSIVE INCOME
For the year ended 30 June 2021
Revenue from oil and gas sales
Cost of sales
Gross profit
Other income
Other expenses
Finance income
Finance costs
Loss before tax
Income tax benefit
Petroleum Resource Rent Tax expense
Total tax benefit
Notes
2
2
2
2
19
19
3
3
2021
$’000
131,734
(117,649)
14,085
2020
$’000
78,139
(54,520)
23,619
7,181
19,828
(41,225)
(147,546)
542
(14,054)
(33,471)
9,158
(5,724)
3,434
1,728
(7,587)
(109,958)
25,575
(1,646)
23,929
Loss after tax for the period attributable to shareholders
(30,037)
(86,029)
Other comprehensive income/(expenditure)
Items that will be reclassified subsequently to profit or loss
Reclassification during the period to profit or loss of realised hedge settlements
Fair value movements on interest rate swaps accounted for in a hedge relationship
Income tax effect on fair value movement on derivative financial instrument
Items that will not be reclassified subsequently to profit or loss
Fair value movement on equity instruments at fair value through other
comprehensive income
Other comprehensive income/(expenditure) for the period net of tax
Total comprehensive loss for the period attributable to shareholders
Basic loss per share
Diluted loss per share
-
-
-
(1,173)
2,140
(383)
20
4
4
(688)
(688)
(690)
(106)
(29,349)
(86,135)
Cents
(1.8)
(1.8)
Cents
(5.3)
(5.3)
The above Consolidated Statement of Comprehensive Income should be read in conjunction with the accompanying notes.
78
COOPER ENERGY ANNUAL REPORT 2021 CONSOLIDATED STATEMENT OF FINANCIAL POSITION
As at 30 June 2021
Assets
Current Assets
Cash and cash equivalents
Trade and other receivables
Prepayments
Inventory
Total Current Assets
Non-Current Assets
Other financial assets
Property, plant and equipment
Intangible assets
Right-of-use assets
Exploration and evaluation assets
Oil and gas assets
Deferred tax asset
Total Non-Current Assets
Exploration assets classified as held for sale
Total Assets
Liabilities
Current Liabilities
Trade and other payables
Provisions
Lease liabilities
Interest bearing loans and borrowings
Total Current Liabilities
Non-Current Liabilities
Provisions
Lease liabilities
Interest bearing loans and borrowings
Other financial liabilities
Deferred Petroleum Resource Rent Tax Liability
Total Non-Current Liabilities
Exploration assets classified as held for sale
Total Liabilities
Net Assets
Equity
Contributed equity
Reserves
Accumulated losses
Total Equity
Notes
2021
$’000
2020
$’000
5
6
7
8
21
11
12
17
13
14
3
10
9
16
17
18
16
17
18
21
3
10
20
20
20
91,308
32,105
11,893
950
131,583
19,996
6,106
822
136,256
158,507
10,964
33,217
2,059
8,625
159,443
570,178
55,993
840,479
21,533
16,366
1,878
9,738
159,078
615,980
46,835
871,408
1,807
–
978,542
1,029,915
34,374
10,453
1,141
60,000
105,968
356,093
10,863
158,000
3,582
17,083
545,621
1,157
21,183
19,902
1,045
26,000
68,130
374,671
12,004
203,438
3,642
16,948
610,703
–
652,746
678,833
325,796
351,082
477,675
14,118
(165,997)
325,796
475,862
11,180
(135,960)
351,082
79
The above Consolidated Statement of Financial Position should be read in conjunction with the accompanying notes.
COOPER ENERGY ANNUAL REPORT 2021 CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
For the year ended 30 June 2021
Balance at 1 July 2020
Loss for the period
Other comprehensive expenditure
Total comprehensive loss for the period
Transactions with owners in their capacity
as owners:
Share based payments
Transferred to issued capital
Balance as at 30 June 2021
Balance at 1 July 2019
Loss for the period
Other comprehensive expenditure
Total comprehensive gain for the period
Transactions with owners in their capacity
as owners:
Share based payments
Transferred to issued capital
Balance as at 30 June 2020
Notes
Issued
Capital
$’000
Reserves
Accumulated
Losses
$’000
$’000
Total
Equity
$’000
475,862
11,180
(135,960)
351,082
-
-
-
-
1,813
-
688
688
(30,037)
(30,037)
-
688
(30,037)
(29,349)
4,063
(1,813)
-
-
4,063
-
477,675
14,118
(165,997)
325,796
20
20
20
20
-
-
-
-
1,465
475,862
474,397
9,247
-
(106)
(106)
(49,931)
(86,029)
-
433,713
(86,029)
(106)
(86,029)
(86,135)
3,504
(1,465)
-
-
3,504
-
11,180
(135,960)
351,082
The above Consolidated Statement of Changes in Equity should be read in conjunction with the accompanying notes.
80
COOPER ENERGY ANNUAL REPORT 2021 CONSOLIDATED STATEMENT OF CASH FLOWS
For the year ended 30 June 2021
Cash Flows from Operating Activities
Receipts from customers
Payments to suppliers and employees
Payments for restoration
Petroleum Resource Rent Tax (paid)/refund
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 oil and gas assets
Interest paid
Net cash flows used in investing activities
Cash Flows from Financing Activities
Repayment of principal portion of lease liabilities
(Repayment of)/Proceeds from 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
5
5
5
5
2021
$’000
119,075
(84,314)
(5,324)
(11,130)
548
(10,796)
8,059
(17,820)
(1,683)
(5,668)
(9,405)
-
(34,576)
(1,045)
(11,438)
-
(12,483)
(39,000)
(1,275)
131,583
91,308
The above Consolidated Statement of Cash Flows should be read in conjunction with the accompanying notes.
2020
$’000
98,327
(49,532)
(2,544)
4,112
1,248
(3,549)
48,062
(5,947)
(2,018)
(35,057)
(38,703)
(9,665)
(91,390)
(698)
11,284
(257)
10,329
(32,999)
293
164,289
131,583
81
COOPER ENERGY ANNUAL REPORT 2021
NOTES TO THE CONSOLIDATED
FINANCIAL STATEMENTS
For the year ended 30 June 2021
Corporate information
The consolidated financial report of Cooper Energy Limited and its controlled entities (“Cooper Energy” or “the Group”) for the year ended
30 June 2021 was authorised for issue in accordance with a resolution of the Directors on 23 August 2021. Cooper Energy Limited is a for profit
company limited by shares incorporated and domiciled in Australia whose shares are publicly traded on the Australian Securities Exchange.
The nature of the operations and principal activities of the Group are described in the Directors’ Statutory Report and Note 1.
Basis of preparation
The financial report is a general-purpose financial report, which has been prepared in accordance with the requirements of the Corporations
Act 2001, Australian Accounting Standards and other authoritative pronouncements of the Australian Accounting Standards Board (AASB) and
International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).
The financial report has also been prepared on a historical cost basis, except for equity instruments measured at fair value through other
comprehensive income and derivative financial instruments measured at fair value through profit and loss.
The financial report is presented in Australian dollars and under the option available to the Group under ASIC Corporations (Rounding in
Financial/Directors’ Reports) Instrument 2016/191, all values are rounded to the nearest thousand dollars ($’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 ruling at that date. Exchange differences
in the consolidated financial statements are taken to the income statement.
A global pandemic was declared in March 2020 in relation to COVID-19. Further information on the Group’s response to COVID-19 has been
included within the Operating and Financial Review.
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.
At the date of this report, it is the directors’ view that there are reasonable grounds to believe that the Group will continue as a going concern,
having considered the matters set out below in the section titled Significant accounting judgements, estimates and assumptions “Funding and
liquidity and progress towards Practical Completion of the Sole Gas Project”.
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
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.
Note 3
Income tax
Note 14
Oil and gas assets
Note 16
Provisions
Note 17
Leases
Note 27
Share based payments
Note 15
Impairment
Note 22
Interests in joint arrangements
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 the Group’s Hydrocarbon Guidelines (www.cooperenergy.com.au/our-company/corporate-governance-and-policies/
hydrocarbon-reporting-policy). A technical understanding of the geological and engineering processes enables the recoverable hydrocarbon
estimates to be determined by using forecasts of production, commodity prices, production costs, exchange rates, tax rates and discount rates.
Recoverable hydrocarbon estimates may change from time to time if any of the forecast assumptions are revised.
82
COOPER ENERGY ANNUAL REPORT 2021 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 30 June 2021
Significant accounting judgements, estimates and assumptions continued
Significant Accounting Judgements, Estimates and Assumptions
Funding and liquidity and progress towards Practical Completion of the Sole Gas Project
Completion of commissioning of the Orbost Gas Processing Plant (OGPP) to process Sole gas by the APA Group remains outstanding and is
yet to meet the contracted performance standards for practical completion, which include demonstrated capacity to supply 68 TJ/day of
Sole gas into the Eastern Gas Pipeline. Foaming and fouling in the absorber section of the plant has impaired output rates from the OGPP.
APA and Cooper Energy entered into a Transition Agreement (TA) which establishes the commercial framework for addressing issues with
performance of the OGPP, commencement of the Sole Gas Sale Agreements (GSAs) over December 2020 and January 2021 and the basis
to collaboratively improve plant performance and hence progress towards Practical Completion of the OGPP. The agreement provides for the
commencement of the term GSAs, payment of the processing tariff to APA for Sole gas processed for the GSAs and the sharing of revenue,
operating and capital costs attributable to spot gas sales until Practical Completion or expiry. Cooper Energy has put in place supplementary
supply arrangements to fulfil gas customer supply obligations if required. In April 2021, the TA was extended by 12 months until 1 May 2022.
Substantial root cause analysis and capital works have been undertaken over a number of months and are ongoing in order to address the
production capacity issues as communicated to the market. Whilst gas processing and servicing of the Sole GSAs has commenced, APA is
continuing absorber testing and commissioning, including undertaking further capital works at the plant to install solids removal equipment and
changing of the liquid distributor within each absorber.
Cooper Energy’s development of the Sole gas field was funded through the Company’s Reserve Based Lending facility (RBL). The syndicate
holds security over the Company’s 2P Reserves and GSAs. The date for Scheduled Project Completion as well as the “long-stop” date being
90 days following Scheduled Project Completion Date set out in the RBL was adjusted, with agreement reached in June 2021 on amendments.
The amendments include realignment of principal repayments through to expiry of the Transition Agreement on 1 May 2022 and re-sculpting of
repayments through to maturity in 2024. The amendments align the RBL with a re-based production level of 40 - 45 TJ/day for the Orbost Gas
Processing Plant, including a revised completion test. Cooper Energy and the lenders continue to have a productive relationship and negotiate
practical resolutions to the technical OGPP issues being addressed above. As at the date of the report, the Group has met and continues to
meet all the requirements under the RBL including covenant requirements The facility requires Cooper Energy to meet financial covenants and
information and general undertakings and allows for a Review Event under certain circumstances.
The uncertainties associated with the progress to Practical Completion of the OGPP have required management to make significant accounting
judgments and estimates.
Impacts on going concern basis and interest-bearing loans and borrowings:
The Group holds significant cash balances of $91.3 million and has drawn debt of $218.0 million as at the end of the reporting period. All debt
covenants have been complied with to the date of this report. Cash flow forecasts for the Group, inclusive of the impact of the TA and under various
reasonably likely scenarios that have been modelled, indicate that the Group can continue to meet its obligations and commitments including servicing
debt for at least the next 12 months from the date of this report under the existing RBL facility. There is judgment involved in assessing the cash flows
post Practical Completion. The directors continue to believe that the lenders will continue to negotiate in good faith as the Practical Completion issues
are resolved. Under the reasonably possible scenarios modelled, the Group maintains at all times, the liquidity levels required under the RBL facility.
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.
New accounting standards and interpretations
New standards, interpretations and amendments thereof, adopted by the Group
The Group has adopted all of the new and revised Standards and Interpretations issued by the Australian Accounting Standards Board
(the AASB) that are relevant to their operations and effective for the 2021 financial year.
Accounting standards, amendments and interpretations applicable on 1 July 2020 have had no material impact on the Group’s financial statements.
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 2021, are outlined below:
AASB 2021-5
Amendments to AASs – Deferred Tax related to Assets and Liabilities arising from a Single Transaction
Summary
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 the 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
Impact on Consolidated
Financial Statements
The impact of this accounting standard amendment on the Group is yet to be determined.
83
COOPER ENERGY ANNUAL REPORT 2021 New accounting standards and interpretations continued
AASB 2020-3
Amendments to AASB 116 – Property Plant and Equipment: Proceeds before Intended Use
Summary
The amendment prohibits entities from deducting from the cost of an item of property, plant and equipment (PP&E),
any proceeds of the sale of items produced while bringing that asset to the location and condition necessary for it to be
capable of operating in the manner intended by management. Instead, an entity recognises the proceeds from selling
such items, and the costs of producing those items, in profit or loss.
Application Date
of the Standard
1 January 2022
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
Provides additional information regarding financial statement lines that are most relevant to explaining the Group’s
performance during the period.
Working capital
Provides additional information regarding financial statement lines that are most relevant to explaining the assets used
to generate the Group’s trading performance during the period.
Capital employed
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.
Funding and risk
management
Provides additional information regarding financial statement lines that are most relevant to explaining the Group’s
funding sources. This section also provides information relating to the Group’s exposure to various financial risks, its
impact on the financial position and performance of the Group and how these risks are managed.
Group structure
Summarises how the group structure affects the financial position and performance of the Group as a whole.
Other information
Includes other information that is disclosed to comply with relevant accounting standards and other pronouncements,
but is not directly related to the individual line items in the financial statement.
Group Performance
1. Segment reporting
Identification of reportable segments and types of activities
The Group identified its reportable segments to be Cooper Basin, South-East Australia (based on the nature and geographic location of the
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:
Cooper Basin
Exploration and evaluation of oil and gas and production and sale of crude oil in the Group’s permits within the Cooper Basin. Revenue is derived
from the sale of crude oil to IOR Energy Pty Ltd and a consortium of buyers made up of Santos Limited (and its subsidiaries), Delhi Petroleum Pty
Ltd and Beach Energy (Operations) Limited.
South-East Australia
The South-East Australia segment primarily consists of the Sole Gas Project, the operated Casino Henry producing gas assets and Athena
Gas Plant, the Manta Gas Project, and the non-operated depleted Minerva field. Revenue is derived from the sale of gas and condensate
to four customers. The segment also includes exploration and evaluation and care and maintenance activities ongoing in the Otway and
Gippsland basins.
84
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 1. Segment reporting continued
Corporate and Other
The Corporate segment includes the revenue and costs associated with the running of the business and includes items which are not directly
allocable to the other segments.
Accounting policies and inter-segment transactions
The accounting policies used by the Group in reporting segments internally is the same as those contained in the financial statements.
Cooper
Basin
$’000
South-East
Australia
Corporate
and Other
$’000
$’000
Consolidated
$’000
30 June 2021
Revenue from oil and gas sales to external customers
Total revenue
Segment result before interest, tax, depreciation,
amortisation and impairment
Depreciation and amortisation
Impairment
Net finance costs
Profit/(loss) before tax
Income tax benefit
Petroleum Resource Rent Tax expense
Net profit/(loss) after tax
Segment assets
Segment liabilities
Additions of non-current assets
Exploration and evaluation assets
Oil and gas assets
Property, plant and equipment
Intangibles
Total additions of non-current assets
12,236
12,236
5,037
(2,641)
(389)
(115)
1,892
-
-
1,892
15,016
7,159
493
988
-
-
1,481
119,498
119,498
-
-
38,946
(20,102)
(38,150)
(2,660)
-
(13,344)
(12,548)
-
(5,724)
(18,272)
782,167
405,776
2,634
(5,997)
17,663
-
14,300
-
(53)
(22,815)
9,158
-
(13,657)
181,359
239,811
-
(3)
157
1,683
1,837
131,734
131,734
23,881
(43,451)
(389)
(13,512)
(33,471)
9,158
(5,724)
(30,037)
978,542
652,746
3,127
(5,012)
17,820
1,683
17,618
Cooper
Basin
$’000
South-East
Australia
Corporate
and Other
$’000
$’000
Consolidated
$’000
30 June 2020
Revenue from oil and gas sales to external customers
Total revenue
Segment result before interest, tax, depreciation,
amortisation and impairment
Depreciation and amortisation
Impairment
Net finance costs
Profit/(loss) before tax
Income tax benefit
Petroleum Resource Rent Tax expense
Net profit/(loss) after tax
14,558
14,558
6,486
(3,573)
(7,836)
(95)
(5,018)
-
-
(5,018)
63,581
63,581
42,937
(23,234)
(99,662)
(3,943)
(83,902)
-
(1,646)
(85,548)
-
-
(17,094)
(2,123)
-
(1,821)
(21,038)
25,575
-
4,537
78,139
78,139
32,329
(28,930)
(107,498)
(5,859)
(109,958)
25,575
(1,646)
(86,029)
85
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
South-East
Australia
Corporate
and Other
1. Segment reporting continued
Segment assets
Segment liabilities
Additions of non-current assets
Exploration and evaluation assets
Oil and gas assets
Property, plant and equipment
Intangibles
Right-of-use assets
Cooper
Basin
$’000
14,969
8,731
6,802
5,579
-
-
-
$’000
802,263
421,656
85,651
48,610
11,593
-
-
$’000
212,683
248,446
-
-
1,481
2,017
2,723
6,221
Consolidated
$’000
1,029,915
678,833
92,453
54,189
13,074
2,017
2,723
164,456
Total additions of non-current assets
12,381
145,854
In 2021, revenue from two customers amounted to $71.1 million, and $21.5 million respectively in the South-East Australia segment. In 2020,
revenue from two customers amounted to $31.9 million, and $27.3 million respectively in the South-East Australia segment and $17.9 million
from one customer in the Cooper Basin segment.
2. Revenues and expenses
Revenue from oil and gas sales
Revenue from contracts with customers
Oil revenue from contracts with customers
Gas 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 oil and gas sales
Other income
Liquidated damages
Other
Restoration income
Total other income
Cost of sales
Production expenses
Royalties
Third-party product purchases
Amortisation of oil and gas assets
Depreciation of property, plant and equipment
Total cost of sales
Other expenses
Selling expense
General administration
Depreciation of property, plant and equipment
Amortisation of intangibles
86
Notes
2021
$’000
2020
$’000
12,141
119,499
131,640
94
94
131,734
-
6
7,175
7,181
(62,510)
(976)
(13,373)
(40,790)
-
(117,649)
(678)
(12,669)
(807)
(742)
15,563
63,581
79,144
(1,005)
(1,005)
78,139
19,800
28
-
19,828
(26,511)
(1,203)
-
(26,452)
(354)
(54,520)
(693)
(15,123)
(828)
(176)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
2. Revenues and expenses
Depreciation of right-of-use assets
Care and maintenance
Restoration expense
Exploration and evaluation expense
Impairment expense
Fair value adjustment of success fee liability
Realised and unrealised foreign currency translation (loss)/gain
Other (including new ventures)
OGPP reconfiguration and commissioning works
Total other expenses
Employee benefits expense included in general administration
Director and employee benefits
Share based payments
Superannuation expense
Total employee benefits expense (gross)
Accounting Policy
Revenue from contracts with customers
Notes
15
2021
$’000
(1,113)
(2,755)
-
(566)
(389)
73
(1,275)
(9,089)
(11,215)
(41,225)
(24,907)
(4,063)
(1,856)
(30,826)
2020
$’000
(1,120)
(3,597)
(14,056)
(3,100)
(107,498)
(123)
119
(1,351)
-
(147,546)
(20,412)
(3,504)
(1,264)
(25,180)
Revenue from contracts with customers is recognised at the point in time when control of the crude oil, natural gas or liquids 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 crude oil, natural gas or liquids, with each barrel of crude oil or GJ of natural gas 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 crude oil, natural gas
or liquids 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
market prices. The crude oil sales price is the Tapis crude oil price, 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.
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
Over provision in respect of prior year income tax
2021
$’000
2020
$’000
-
-
(22,166)
31,324
-
9,158
(504)
(504)
14,632
11,438
9
26,079
87
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
3. Income Tax continued
Income tax benefit
Current Petroleum Resource Rent Tax
Current year
Adjustments in respect of prior year income tax
Deferred Petroleum Resource Rent Tax
Origination and reversal of temporary differences
Petroleum Resource Rent Tax expense
Total tax benefit
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% (2020: 30%)
(Increase)/decrease in income tax expense due to:
Non-deductible expenditure
Adjustments in respect to current income tax of previous years
Recognition of royalty related income tax benefits
Permanent difference arising from impairment expense
Other
Income tax benefit
Petroleum Resource Rent Tax expense
Total tax benefit
Tax Consolidation
2021
$’000
9,158
(5,589)
-
(5,589)
(135)
(135)
(5,724)
3,434
2020
$’000
25,575
(5,686)
3,299
(2,387)
741
741
(1,646)
23,929
(33,471)
(109,958)
10,041
32,987
(2,945)
-
41
-
2,021
9,158
(5,724)
3,434
(187)
9
197
(8,112)
681
25,575
(1,646)
23,929
Cooper Energy Limited and its 100% owned Australian resident subsidiaries are consolidated for Australian income tax purposes with Cooper
Energy Limited being the head entity of the tax consolidated group. Members of the Group entered into a tax sharing arrangement in order to
allocate income tax expense to the wholly-owned subsidiaries. In addition, the agreement provides for the allocation of income tax liabilities
between the entities should the head entity default on its tax payment obligations.
Members of the tax consolidated group have entered into a tax funding agreement. The tax funding agreement requires members of the tax
consolidated group to make contributions to the head Company for tax liabilities and deferred tax balances arising from transactions occurring
after the implementation of tax consolidation. Contributions are payable following the payment of the liabilities by Cooper Energy Limited.
The assets and liabilities arising under the tax funding agreement are recognised as inter-company assets and liabilities with a consequential
adjustment to income tax expense or benefit. In addition, the agreement provides for the allocation of income tax liabilities between the entities
should the head entity default on its tax payment obligations or upon leaving the Group. The current and deferred tax amounts are measured in a
systematic manner that is consistent with the broad principles in AASB 112 Income Taxes.
Unrecognised temporary differences
At 30 June 2021, 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 (2020: $nil).
Franking Tax Credits
At 30 June 2021 the parent entity had franking tax credits of $42.9 million (2020: $42.9 million). The fully franked dividend equivalent is
$142.9 million (2020: $142.9 million).
88
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 3. Income Tax continued
Petroleum Resource Rent Tax (PRRT)
Cooper Energy Limited has recognised a Deferred Tax Liability for Petroleum Resource Rent Tax (PRRT) of $17.1 million (2020: $16.9 million)
relating to PRRT on the Group’s producing gas assets. The Group has not recognised a Deferred Tax Asset for PRRT of $33.6 million (2020:
$29.0 million). In the current year, this is in respect of the Sole Gas Project, and the Deferred Tax Asset for Sole will be recognised when it is
probable that the undeducted expenditure will be able to be utilised.
Income Tax Losses
(a) Revenue Losses
A Deferred Tax Asset has been recognised for the year ended 30 June 2021 of $66.4 million (2020: $35.0 million).
(b) Capital Losses
Cooper Energy has not recognised a Deferred Tax Asset for Australian income tax capital losses of $15.5 million (2020: $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.
Deferred income tax from corporate tax
Deferred income tax at 30 June relates to:
Deferred tax liabilities
Trade and other receivables
Oil and gas assets
Exploration and evaluation
Property, plant and equipment
Other
Deferred tax assets
Leases
Provision for employee entitlements
Provisions
Other
Capital raising costs
Tax losses
Deferred tax benefit
Deferred tax asset from corporate tax
55,993
46,835
Deferred income tax from PRRT
Deferred income tax at 30 June relates to:
Deferred tax liabilities
Oil and gas assets
Deferred tax (expense)
17,083
16,948
-
-
Deferred tax liability from PRRT
17,083
16,948
Consolidated
Statement of
Financial Position
Consolidated
Statement of
Comprehensive Income
2021
$’000
2020
$’000
2021
$’000
2020
$’000
5,191
45,933
19,116
40
-
(62)
(5,253)
2,302
33,974
17,118
40
83
(11,959)
(13,649)
(1,998)
(8,825)
-
83
-
20
70,280
51,153
(19,127)
(20,152)
651
1,049
992
1,422
(341)
(373)
47,865
53,392
(5,527)
9,976
342
66,390
126,273
5,903
1,213
35,066
97,988
4,073
(871)
31,324
28,285
9,158
993
(660)
34,982
525
(1,048)
11,438
46,230
26,078
25
25
89
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 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 at 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 exits 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 (PRRT)
For PRRT purposes, the impact of future augmentation on expenditure is included in the determination of future taxable profits when assessing
the extent to which a deferred tax asset can be recognised in the statement of financial position. Deferred tax assets are reduced to the extent
that it is no longer probable that the related tax benefit will be realised.
Goods and Services Taxes (GST)
Revenues, expenses and assets are recognised net of the amount of GST. Receivables and payables are stated inclusive of the amount
of GST receivable or payable. The net amount of GST recoverable from, or payable to, the taxation authority is included as part of receivables
or payables in the Consolidated Statement of Financial Position. Commitments and contingencies are disclosed net of the amount of GST
recoverable from, or payable to, the taxation authority.
Cash flows are included in the Cash Flow Statement on a net basis and the net GST component of cash flows arising from investing
and financing activities, which is recoverable from, or payable to, the taxation authority, are classified as operating cash flows.
Significant Accounting Judgements, Estimates and Assumptions
The Group has a Tax Risk Management Framework which outlines how the direct and indirect tax obligations of Cooper Energy Limited are
met from an operational, governance and tax risk management perspective.
Management judgements are made in relation to the types of arrangements considered to be a tax on income (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 Petroleum Resource Rent Tax legislation, are recognised only where it is considered more likely than not 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.
90
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 4. Earnings per share
The following reflects the net (loss)/profit and share data used in the calculations of earnings per share:
Net loss after tax attributable to shareholders
2021
$’000
2020
$’000
(30,037)
(86,029)
2021
Thousands
2020
Thousands
Weighted average number of ordinary shares used in calculating basic earnings per share
1,629,017
1,624,260
Dilutive performance rights and share appreciation rights1
-
-
Weighted average number of ordinary shares used in calculating dilutive earnings per share
1,629,017
1,624,260
Basic loss per share for the period (cents per share)
Diluted loss per share for the period (cents per share)
(1.8)
(1.8)
(5.3)
(5.3)
1. The weighted average number of potentially dilutive shares at 30 June 2021 is 19.6 million (2020: 12.4 million)
At 30 June 2021 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.
91
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Working Capital
5. Cash and cash equivalents and term deposits
Current Assets
Cash at bank and in hand
Term deposits at bank
Cash and cash equivalents
Reconciliation of net profit to net cash flows from operating activities
Net (loss)/profit after tax
Add/(deduct) non-cash items:
Amortisation of oil and gas 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)/decrease in trade and other receivables
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
2021
$’000
91,308
-
91,308
2021
$’000
2020
$’000
111,567
20,016
131,583
2020
$’000
(30,037)
(86,029)
40,790
807
742
1,113
389
566
(7,175)
4,063
3,255
1,275
756
16,544
(12,108)
(128)
(5,787)
(9,022)
26,475
(7,915)
8,059
26,452
1,182
176
1,120
107,498
3,100
14,056
3,504
4,038
(119)
455
75,433
1,173
(396)
(3,760)
(25,424)
2,750
(1,714)
48,062
Balance at beginning of period
Financing cash flows¹
Non-cash financing movements²
Balance at end of period
Borrowings
Lease Liabilities
2021
$’000
229,438
(11,438)
-
218,000
2020
$’000
213,680
11,284
4,474
229,438
2021
$’000
13,049
(1,045)
-
12,004
2020
$’000
-
(698)
13,747
13,049
1. Financing cash flows consist of the net amount of proceeds from borrowings and repayment of lease liabilities in the statement of cash flows.
2. The movement in borrowings is amortisation of prepaid financing costs, and movement in lease liabilities represents the lease liability
recognised on adoption of AASB 16 Leases.
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.
92
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 6. Trade and other receivables
Current Assets
Trade receivables
Accrued revenue
Interest receivable
2021
$’000
12,380
19,694
31
32,105
2020
$’000
17,783
2,176
37
19,996
Expected credit losses in respect of trade and other receivables is set out in Note 21.
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
Other prepayments
8. Inventory
Spares and parts
2021
$’000
3,396
8,265
232
11,893
2020
$’000
950
2020
$’000
1,530
4,384
192
6,106
2020
$’000
822
All inventory items are carried at cost in the current and previous financial years.
Accounting Policy
Inventories are carried at the lower of their cost or net realisable value. Inventories held by the Group are in respect of spares and parts
involved in drilling operations. Items held as insurance or capital spares are treated as part of property, plant and equipment.
9. Trade and other payables
Trade payables
Accruals (capital and operating expenditure)
2021
$’000
14,092
20,282
34,374
2020
$’000
14,844
6,339
21,183
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.
93
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
10. Exploration assets held for sale
A Sale and Purchase Agreement for the sale to Bass Oil of the Company’s interests in several of its Cooper Basin exploration and production
licenses (PEL 93, PPL 207, PRL 237, PEL 100 and PEL 110) was announced on 12 July 2021 for consideration of $0.7 million. The assets and
associated liabilities are classified as held for sale and presented in separate lines in the Consolidated Statement of Financial Position. The
assets are included within the Cooper Basin segment, refer to Note 1. The net assets relating to the above licenses have been impaired to their
Level 3 fair value less cost to sell, refer to Note 21.
Exploration assets held for sale
Total assets held for sale
Restoration Provisions associated with assets held for sale
Total restoration provisions held for sale
Net assets held for sale
Capital Employed
11. Property, plant and equipment
2021
$’000
1,807
1,807
(1,157)
(1,157)
650
2020
$’000
-
-
-
-
-
Production assets
Corporate assets
Total
2021
$’000
2020
$’000
2021
$’000
2020
$’000
2021
$’000
2020
$’000
Reconciliation of carrying amounts at
beginning and end of period:
Carrying amount at beginning of period
11,676
Assets acquired
Additions
Restoration
Depreciation
-
17,663
(162)
-
543
8,674
2,813
-
(354)
Carrying amount at end of period
29,177
11,676
Cost
Accumulated depreciation
Carrying amount at end of period
33,004
(3,827)
29,177
15,567
(3,891)
11,676
4,690
-
157
-
(807)
4,040
7,713
(3,673)
4,040
4,037
-
1,481
-
(828)
4,690
7,556
(2,866)
4,690
16,366
-
17,820
(162)
(807)
33,217
40,717
(7,500)
33,217
4,580
8,674
4,294
-
(1,182)
16,366
23,123
(6,757)
16,366
Accounting Policy
Property, plant and equipment comprises office and IT equipment, leasehold improvements and the Athena Gas Plant, and is stated at
historical cost less accumulated depreciation and any accumulated impairment losses (refer to Note 15 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 asset’s estimated useful lives. 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.
94
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
12. Intangible assets
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at beginning of period
Additions
Disposals/written off
Amortisation
Carrying amount at end of period
Cost
Accumulated amortisation
Carrying amount at end of period
Accounting Policy
2021
$’000
1,878
1,683
(760)
(742)
2,059
2,808
(749)
2,059
2020
$’000
36
2,018
-
(176)
1,878
2,054
(176)
1,878
Intangible assets comprise software and is 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.
13. Exploration and evaluation assets
Reconciliation of carrying amounts at beginning and end of period
Carrying amount at beginning of period
Additions
Exploration and evaluation expense
Impairment
Transfer to oil and gas assets
Exploration expenditure classified as held for sale
Carrying amount at end of period¹
Notes
15
2021
$’000
159,078
3,127
(566)
(389)
-
(1,807)
159,443
2020
$’000
152,268
92,453
(3,100)
(79,398)
(3,145)
-
159,078
1. Recoverability is dependent on the successful development and commercial exploration or sale of the respective areas of interest.
95
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
13. Exploration and evaluation assets continued
Accounting Policy
Exploration and evaluation expenditure include costs incurred in the search for hydrocarbon resources and determining the commercial
viability in each identifiable area of interest. Exploration and evaluation expenditure is accounted for in accordance with the successful
efforts method and is capitalised to the extent that:
i.
the rights to tenure of the areas of interest are current and the Group controls the area of interest in which the expenditure has been
incurred; and
ii. such costs are expected to be recouped through successful development and exploration of the area of interest, or alternatively by
its sale; or
iii. exploration and evaluation activities in the area of interest have not at the reporting date:
a. reached a stage which permits a reasonable assessment of the existence or otherwise of economically recoverable reserves; and
b. active and significant operations in, or in relation to, the area of interest are continuing.
An area of interest refers to an individual geological area where the potential presence of an oil or a natural gas field is considered
favourable or has been proven to exist, and in most cases, comprises an individual prospective oil or gas field.
Exploration and evaluation expenditure which does not satisfy these criteria is written off. Specifically, costs carried forward in respect of
an area of interest that is abandoned or costs relating directly to the drilling of an unsuccessful well are written off in the year in which the
decision to abandon is made or the results of drilling are concluded. The success or otherwise of a well is determined by reference to the
drilling objectives for that well. For successful wells, the well costs remain capitalised on the 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-iii above are no longer met, the Group will test for impairment in accordance with the impairment policy stated in Note 15.
Where an ownership interest in an exploration and evaluation asset is exchanged for another, the transaction is recognised by reference
to the carrying value of the original interest. Any cash consideration paid, including transaction costs, is accounted for as an acquisition
of exploration and evaluation assets. Any cash consideration received, net of transaction costs, is treated as a recoupment of costs
previously capitalised with any excess accounted for as a gain on disposal of non-current assets. Where a discovered oil or gas field
enters the development phase the accumulated exploration and evaluation expenditure is tested for impairment and then transferred to
oil and gas assets.
14. Oil and gas assets
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at beginning of period
Additions¹
Transferred from exploration and evaluation
Amortisation
Impairment
Carrying amount at end of period
Cost
Accumulated amortisation & impairment
Carrying amount at end of period
1. Includes movements from reset of restoration provisions.
Accounting Policy
Notes
2021
$’000
2020
$’000
15
615,980
(5,012)
-
(40,790)
-
570,178
759,522
(189,344)
570,178
613,198
54,189
3,145
(26,452)
(28,100)
615,980
764,534
(148,554)
615,980
Oil and gas 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 is also included in the
carrying amount of oil and gas 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.
Oil and gas assets are amortised on the Units of Production basis using the latest approved estimate of Proved and Probable (2P) 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. Oil and gas assets are subject to impairment testing, refer to Note 15.
96
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
14. Oil and gas assets continued
Significant Accounting Judgements, Estimates and Assumptions
Estimation of oil and gas asset expenditure
Capitalised oil and gas 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 oil and gas assets
The amortisation of oil and gas 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 49 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 oil and gas assets and
recognition of restoration assets, refer to Note 15 and Note 16 respectively.
15. Impairment
Exploration and evaluation assets
Oil and gas assets
2021
$’000
389
-
389
2020
$’000
79,398
28,100
107,498
The impairment losses recognised in the 2021 financial year relate to the Group’s exploration licenses held for sale being written down to their
fair value less costs to sell. Refer Note 10.
During the year, the Group’s oil and gas assets were assessed for impairment indicators in accordance with AASB 136 Impairment of Assets.
There were no impairment indicators present, therefore no impairment was recognised on oil and gas assets.
In the previous financial year, the Sole asset was tested for impairment as indicators of impairment existed, notably the delay experienced by
APA Group (APA) in commissioning the OGPP. No impairment of the Sole asset was recognised at 30 June 2020. The commissioning delay is
the result of foaming in absorber vessels of the Sulphur Recovery Unit of the OGPP, which has restricted gas processing capacity, preventing the
plant from producing at nameplate capacity of 68 TJ/d. On 20 August 2020, Cooper Energy and APA announced that they had entered into
a Transition Agreement (TA). This agreement was extended by 12 months to 1 May 2022 as announced to the market on 12 April 2021.
Despite the ongoing commissioning delay, trigger test modelling presented no indicators of impairment at 30 June 2021, thereby not requiring
formal recoverable amount testing of the Sole asset at year end.
As outlined in the financial report for the previous financial year, whilst the Sole asset has not been impaired, its value remains sensitive to
variables including, but not limited to:
• the timing of and costs required to achieve nameplate processing capacity of 68 TJ/d
• processing capacity levels attained both pre and post reconfiguration and commissioning works.
Adverse outcomes in one or more of the variables may give rise to an impairment of the asset in future periods.
Accounting Policy
The carrying values of non-current assets, including, property, plant and equipment, capitalised exploration and evaluation assets and
oil and gas assets are assessed for indicators of impairment biannually. Where indicators of impairment are present, an impairment test
is performed.
An impairment loss is recognised for the amount by which the asset or CGU’s carrying amount exceeds its recoverable amount. The
recoverable amount of a non-current asset or CGU is the higher of value in use (VIU) and fair value less costs of disposal (FVLCD). For the
purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (CGUs).
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 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.
97
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 15. Impairment continued
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 oil and gas 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 oil and gas 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 oil and gas assets
The Group reviews the carrying amount of oil and gas assets at each reporting date starting with analysis of any indicators of impairment
and where relevant may prepare 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.
16. Provisions
Current Liabilities
Employee provisions
Restoration provisions
Non-Current Liabilities
Employee provisions
Restoration provisions
Movement in carrying amount of the current restoration provision:
Carrying amount at beginning of period
Restoration expenditure incurred
New provisions and changes in restoration assumptions
Transferred (to)/from non-current provisions
Carrying amount at end of period
98
2021
$’000
2,459
7,994
10,453
441
355,652
356,093
2021
$’000
17,899
(8,445)
-
(1,460)
7,994
2020
$’000
2,003
17,899
19,902
367
374,304
374,671
2020
$’000
9,989
(2,380)
-
10,290
17,899
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 16. Provisions continued
Movement in carrying amount of the non-current restoration provision:
Carrying amount at beginning of period
New provisions and changes in restoration assumptions
Provision through asset acquisition
Transferred from/(to) current provisions
Increase through accretion
Change in discount rate
Restoration expenditure classified as held for sale
Carrying amount at end of period
2021
$’000
374,304
(4,746)
-
1,460
3,243
(17,452)
(1,157)
355,652
2020
$’000
276,228
88,473
4,957
(10,290)
4,001
10,935
-
374,304
The current planning case for the abandonment and remediation work on BMG has a timing expectation on the works completing in the 2023
calendar year subject to rig availability and regulatory approvals.
The discount rate used in the calculation of the provisions as at 30 June 2021 ranged from 0.05% to 2.25% (2020: 0.24% to 1.72%) 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 government
bond rates since the last assessment.
Accounting Policy
Provisions are recognised when the Group has a legal or constructive obligation as a result of past transactions or other past events, it is
probable that a future sacrifice of economic benefits will be required and a reliable estimate can be made of the amount of the obligation.
Employee benefits
Liabilities for wages and salaries, including non-monetary benefits and annual leave are recognised in respect of employees’ services up to the
reporting date and are measured at the amount expected to be paid when the liabilities are settled. Expenses for non-accumulating sick leave
are recognised when the leave is taken and are measured at the rates paid or payable.
The provision for long service leave is recognised and measured as the present value of expected future payments to be made in respect
of services provided by employees up to the reporting date using the projected unit credit method. Consideration is given to expected future
wage and salary levels, experience of employee departures, 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.
A restoration provision is recognised upon commencement of construction and then reviewed biannually 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. The unwinding of the discount is recorded as an
accretion charge within finance costs.
Any changes in the estimate of the provision for restoration arising from changes in the gross cost estimate or changes in the discount rate of
the restoration provision are recorded by adjusting the provision and the carrying amount of the production or exploration asset, to the extent
that it is appropriate to recognise an asset under accounting standards, and then depreciated over the remaining producing life of the asset.
Where it is not appropriate to recognise an asset, changes will 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.
99
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 16. Provisions continued
Significant Accounting Judgements, Estimates and Assumptions
Provisions for restoration costs
Decommissioning and restoration costs are a normal consequence of oil and gas 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 on 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 ultimate costs can vary in response to many factors. These
include the extent of restoration required due to changes to the relevant legal or regulatory requirements and the emergence of new restoration
techniques or experience at other fields, including prevailing service costs. The expected timing of expenditure can also change, for example
in response to changes in oil and gas 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 Company’s restoration provision for offshore assets is based on recovering subsea trees and manifolds and recovery of flowlines and
umbilicals to a certain distance from shore and at a certain depth of water. The Company’s restoration provision for onshore production
facilities, is based on demolition and removal of the facilities, removal of contaminated soil and revegetation of the affected area.
17. 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
Transition – Right-of-use assets recognised 1 July 2019
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
Transition - Lease liabilities recognised 1 July 2019
Additions
Accretion of interest
Payments
Carrying amount at end of period
Current
Non-Current
100
2021
$’000
9,738
-
-
(1,113)
8,625
10,858
(2,233)
8,625
2021
$’000
13,049
-
-
598
(1,643)
12,004
1,141
10,863
2020
$’000
-
8,135
2,723
(1,120)
9,738
10,858
(1,120)
9,738
2020
$’000
-
9,378
4,624
634
(1,587)
13,049
1,045
12,004
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
17. Leases continued
Short-term and low-value lease asset exemptions
For the year ending 30 June 2021, 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
2021
$’000
100
167
267
2020
$’000
-
18
18
The Group had total cash outflows for leases of $1.6 million in 2021, including leases for short-term leases and low-value assets. The future cash
outflows relating to leases that have not yet commenced are disclosed in Note 25.
Orbost Gas Processing Plant
Under AASB 16, the Group will recognise a right-of-use asset and corresponding lease liability in relation to the OGPP. The Sole Gas Processing
Agreement (GPA) creates a right-of-use asset and will be recognised at an amount equal to the corresponding lease liability. The Group expects
to recognise a right-of-use asset and lease liability under AASB 16 for the OGPP at the date the underlying asset is available for use. The
Group expects the agreement, which was entered into prior to 1 July 2019, to result in a right-of-use asset and lease liability of approximately
$250 million to $280 million based on current information, with recognition expected to occur in the second half of the 2022 financial year once
the asset is available for use and the GPA or arrangements on like terms commence. The final value that will be recorded for the right-of-
use asset and lease liability is dependent on a number of factors that will be known at the time the asset is available for use. These amounts
may change depending on production volumes per annum, the timing of commencement of the lease, annual indexation to be applied and
other factors. The Transition Agreement entered into with APA Group on 20 August 2020 has not triggered commencement of the lease.
AASB 16 requires that the lessee’s rate implicit in the lease arrangement be used to measure the present value of the lease liability, unless that
cannot be determined, in which case the incremental borrowing rate should be used. In determining the discount rate applicable to the OGPP
lease liability, the Group will use the rate implicit in the lease.
The contract includes non-lease payments for services which do not form part of the lease liability and will be recognised as production costs
as incurred. The lease charge is calculated based on the lease component payment required under the agreements.
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). The right-of-use assets are initially measured at a value equal to the 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, the right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any
remeasurement of lease liabilities. The property right-of-use assets are depreciated on a straight-line basis over the shorter of its estimated
useful life and the lease term. Right-of-use assets are also allocated to Cash Generating Units (CGUs) when testing for impairment (refer to
Note 15). Lease liabilities are excluded from the carrying amount of a CGU.
At the commencement date of the lease, the Group recognises lease liabilities measured at 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 eases of low-
value assets are recognised as 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.
101
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Funding and Risk Management
18. Interest bearing loans and borrowings
Current bank debt
Non-current bank debt
2021
$’000
60,000
158,000
2020
$’000
26,000
203,438
In August 2017, Cooper Energy negotiated a $250.0 million senior secured Reserve Based Lending Facility, principally to fund the Sole
Gas Project, and a senior secured $15.0 million working capital facility. Cooper Energy is in compliance with all covenants at 30 June 2021.
A summary of the Group’s secured facilities is included below.
Facility
Currency
Limit1
Utilised amount
Accounting balance
Effective interest rate
Maturity²
Facility
Currency
Limit
Utilised amount3
Accounting balance
Reserve Based Lending Facility
Australian dollars
$218.0 million (2020: $250.0 million)
$218.0 million (2020: $229.4 million)
$218.0 million (2020: $229.4 million)
4.36% floating
2021 – 2024
Working Capital Facility
Australian Dollars
$15 million (2020: $15 million)
$8.8 million (2020: $1.5 million)
Nil (2020: Nil)
Effective interest rate
Nil
Maturity
28 September 2022
1. As at 30 June 2021, $218.0 million of the facility limit of $250.0 million remains available.
2. Repayment profile based on the facility repayment schedule, the reserves profile at completion of the Sole Gas Project and the facility
maturity date.
3. As at 30 June 2021, there have been no cash draw downs. $8.8 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 an unconditional 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.
102
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 19. Net finance costs
Finance Income
Interest income
Finance Costs
Accretion of restoration provision
Accretion of success fee liability
Finance costs associated with lease liabilities
Interest expense
Capitalised interest
Total finance costs
Net finance costs
Accounting Policy
2021
$’000
2020
$’000
542
1,728
(3,243)
(12)
(598)
(4,001)
(37)
(634)
(10,201)
(12,580)
-
(14,054)
(13,512)
9,665
(7,587)
(5,859)
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.
20. Contributed equity and reserves
Capital Management
For the purpose of the Group’s 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 is to maintain an appropriate capital profile to support its business
activities and to maximise shareholder value. At 30 June 2021, the Group has utilised $218.0 million of its Reserve 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.
Share capital
Ordinary shares issued and fully paid
Movement in ordinary shares on issue
At 1 July
2021
$’000
2020
$’000
477,675
475,862
2021
2020
Thousands
$’000
Thousands
$’000
1,626,647
475,862
1,621,551
474,397
Issuance of shares for Performance Rights and Share Appreciation Rights
4,379
1,813
5,096
1,465
At 30 June
1,631,026
477,675
1,626,647
475,862
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.
The Group may issue shares to contractors at its discretion in exchange for services rendered. The cost of these issued shares is measured by
reference to the fair value at the date at which they are granted.
103
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
20. Contributed equity and reserves continued
Reserves
Consolidation
reserve
$’000
Share
based
payment
reserve
$’000
Option
premium
reserve
$’000
Cash flow
hedge
reserve
$’000
Equity
instrument
reserve
$’000
Consolidated
At 1 July 2019
Other comprehensive expenditure
Transferred to issued capital
Share-based payments
At 30 June 2020
Other comprehensive income/
(expenditure)
Transferred to issued capital
Share-based payments
At 30 June 2021
Nature and purpose of reserves
Consolidation reserve
(541)
10,791
-
-
-
(541)
-
-
-
-
(1,465)
3,504
12,830
-
(1,813)
4,063
(541)
15,080
25
-
-
-
25
-
-
-
25
(584)
584
-
-
-
-
-
-
-
Total
$’000
9,247
(106)
(1,465)
3,504
11,180
(444)
(690)
-
-
(1,134)
688
688
-
-
(1,813)
4,063
(446)
14,118
The 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.
Cash flow hedge reserve
This reserve is used to capture the effective portion of the mark to market movement of instruments designed in a hedge relationship.
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.
2021
$’000
2020
$’000
(135,960)
(30,037)
(165,997)
(49,931)
(86,029)
(135,960)
Accumulated Losses
Movement in accumulated losses:
Balance at 1 July
Net loss for the year
Balance at 30 June
104
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 21. Financial risk management
The Group’s principal financial instruments comprise cash and short-term deposits (Note 5), receivables (Note 6), payables (Note 9), borrowings
(Note 18) and other financial assets and liabilities as disclosed in the below table.
Other financial assets – Non-Current
Equity instruments¹
Escrow proceeds receivable
2021
$’000
1,252
9,712
10,964
1. The equity instruments consist of two investments and 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
Fair value hierarchy
3,582
3,582
3,642
12
(72)
3,582
2020
$’000
564
20,968
21,532
3,642
3,642
3,482
37
123
3,642
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:
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
2
1
2
2
3
2
Carrying amount
Fair value
Level
2021
$’000
2020
$’000
2021
$’000
2020
$’000
19,996
564
20,969
21,183
3,642
32,105
19,996
32,105
1,252
9,712
34,374
3,582
564
20,969
21,183
3,642
1,252
9,712
34,374
3,582
218,000
229,438
216,802
230,705
105
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 21. Financial risk management continued
The following summarises the significant methods and assumptions used in estimating the fair values of financial instruments:
Equity instruments
Equity instruments are not held for trading and measured at fair value through other comprehensive income based on an irrevocable election
made at inception on an instrument basis and 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, and hence is 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 sale is 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, a portion of these funds were used to pay the Group’s share of OGPP reconfiguration and
commissioning works.
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 acquired on 7 May 2014. The significant unobservable (level 3) valuation inputs
for the success fee financial liability includes: a probability of 33% that no payment is made and a probability of 67% the payment is made in
2024. The discount rate used in the calculation of the liability as at 30 June 2021 equalled 0.52% (June 2020: 0.49%). The financial liability is
measured at fair value through profit and loss and valued using a discounted cash flow model and the value is sensitive to changes in discount
rate and probability of payment. Significant changes in any of the significant unobservable inputs would result in significantly higher or lower fair
value measurement.
Risk Management
The Group manages its exposure to key financial risks in accordance with its risk management policy with the objective to ensure that the
financial risks inherent in oil and gas 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 forecast for interest
rates, foreign exchange 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 2021 and 30 June 2020. 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. This is based on the financial assets and financial liabilities
held at 30 June 2021 and 30 June 2020.
The Group has transactional currency exposure arising from oil sales which are denominated in United States dollars, whilst almost all its costs
are denominated in Australian dollars.
The majority of costs are denominated in Australian dollars, however there are 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.
106
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 21. Financial risk management continued
a) Foreign currency risk
The Group may from time to time have cash denominated in United States dollars (US dollars).
Currently 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
b) Commodity price risk
2021
$’000
7,044
4,124
2020
$’000
13,830
2,176
The Group uses oil price options to manage some of its transaction exposures. Options entered into have not been designated as cash flow
hedges and are entered into for periods consistent with oil price exposure of the underlying transactions, generally from one to 12 months.
Commodity price risk arises from the sale of oil denominated in US dollars. The Group has provisional sales at 30 June 2021 of $4.1 million
(2020: $2.2 million).
c) Interest rate risk
The Group has borrowings of $218.0 million at 30 June 2021 (2020: $229.4 million). Interest on borrowings is at variable rates (refer to Note 18)
and are capitalised while the project is in development. The Group has fixed rate term deposits that are not impacted by changes in the interest
rate at 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.
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 Brent Average price were 10% higher at the balance date
If the Brent Average price were 10% lower at the balance date
If the interest rates were 10% higher at the balance date
If the interest rates 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
2021
$’000
2020
$’000
Impact on after tax profit
(1,015)
1,241
452
(452)
(2,180)
2,180
125
(125)
(1,455)
1,778
397
(397)
(2,294)
2,294
Impact on reserve
56
(56)
107
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 21. Financial risk management continued
Credit risk
Credit risk arises from the financial assets of the Group which comprise cash and cash equivalents and trade and other receivables including
hedge settlement receivables, escrow proceeds receivable (disclosed as other financial assets), and certain prepayments. The Group’s exposure
to credit risk arises from potential default of the counter party, 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 $4.2 million
calculated on lifetime expected credit loss has been recognised in respect of credit-impaired receivables.
Cash and cash equivalents, term deposits and escrow proceeds receivable are held at three financial institutions that have a Standard & Poor’s A
credit rating or better.
Liquidity risk
Liquidity risk is the risk that the Group will not be able to meet its financial obligations as they fall due. The liquidity position of the Group is
managed to ensure sufficient liquid funds are available to meet all financial commitments in a timely and cost-effective manner. The Managing
Director and Chief Financial Officer review the liquidity position on a regular basis including cash flow forecasts to determine the forecast liquidity
position and maintain appropriate liquidity levels.
Any fluctuation of the interest rate either up or down will have no 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:
At 30 June 2021
Trade and other payables
Lease liabilities
Interest bearing loans and borrowings
Success fee financial liability
At 30 June 2020
Trade and other payables¹
Lease liabilities
Interest bearing loans and borrowings
Success fee financial liability
1. Excludes deferred lease incentive.
Less than
3 months
$’000
3 to 12
months
$’000
1 to 5
years
$’000
Greater than
5 years
$’000
34,372
275
9,394
-
-
864
-
7,459
59,722
168,955
-
5,000
-
3,406
-
-
44,041
60,586
181,414
3,406
21,183
258
2,530
-
-
786
35,192
-
23,971
35,978
-
6,887
218,017
5,000
229,904
-
5,118
-
-
5,118
Total
$’000
34,372
12,004
238,071
5,000
289,447
21,183
13,049
255,739
5,000
294,971
108
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Group Structure
22. 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:
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 93¹,²
Oil and gas exploration and production
PRL 237²
Oil and gas exploration
Ownership Interest
2021
2020
50%
50%
50%
30%
20%
50%
50%
-
30%
20%
PRL 207-209 (Formerly PEL 100)²
Oil and gas exploration
19.165%
19.165%
PRL 183-190 (Formerly PEL 110)²
Oil and gas exploration
PEL 494
PEP 150
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
Oil and gas exploration
PRL 85-104¹ (Formerly PEL 92)
Oil and gas exploration and production
1. Includes associated PPLs.
20%
30%
50%
50%
75%
30%
30%
25%
20%
30%
50%
50%
75%
30%
-
25%
2. The assets and liabilities associated with these joint arrangements are held for sale as at 30 June 2021. Refer to Note 10.
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
Significant Accounting Judgements, Estimates and Assumptions
Joint arrangements
Judgement is required to determine when the Group has joint control over an arrangement, which requires an assessment of the relevant
activities and when the decisions in relation to those activities require unanimous consent. The Group has determined that the relevant
activities for its joint arrangements are those relating to the operating and capital decisions of the arrangement, such as approval of the capital
expenditure program for each year and appointing, remunerating and terminating the key management personnel or service providers of the
joint arrangement. Where joint control does not exist, the relationship is not accounted for as a joint arrangement.
The considerations made in determining joint control are similar to those necessary to determine control over subsidiaries.
Judgement is also required to classify a joint arrangement. Classifying the arrangement requires the Group to assess their rights and
obligations arising from the arrangement. Specifically, the Group considers:
• the structure of the joint arrangement – whether it is structured through a separate vehicle; and
• when the arrangement is structured through a separate vehicle, the rights and obligations arising from the legal form of the separate vehicle,
the terms of the contractual arrangement, and other facts and circumstances (when relevant).
This assessment often requires significant judgement, and a different conclusion on joint control and also whether the arrangement is a joint
operation or a joint venture, may materially impact the accounting.
109
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
23. Investments in controlled entities
(a) 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.
Name
CE Tunisia Bargou Ltd
CE Hammamet Ltd
CE Nabeul Ltd
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
Cooper Energy (BMG) Pty Ltd
Cooper Energy (CB) Pty Ltd
Cooper Energy (Finance) Pty Ltd
Cooper Energy (AGP) Pty Ltd
Country of
incorporation
British Virgin Islands
British Virgin Islands
British Virgin Islands
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Ownership interest
Note
2021
-
-
-
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)(b)
(a)(b)
(a)(b)
(a)(b)
2020
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
-
The parties that comprise the Closed Group are denoted by (a). Parties added to the Closed Group by assumption deed dated 28 August 2020
are denoted by (b).
(b) Deed of Cross Guarantee
Pursuant to ASIC Corporations (Wholly-owned Companies) Instrument 2016/785 dated 29 September 2016, relief has been granted to these
controlled entities of Cooper Energy Limited from the Corporations Act 2001 for preparation, audit and lodgement of financial reports, and
directors’ reports. As a condition of the Class Order, Cooper Energy Limited, and the controlled entities subject to the Class Order, entered into a
Deed of Cross Guarantee. The effect of the deed is that Cooper Energy Limited has guaranteed to pay any deficiency in the event of the winding
up of any member of the Closed Group, and each member of the Closed Group has given a guarantee to pay any deficiency, in the event that
Cooper Energy Limited or any other member of the Closed Group is wound up.
CE Tunisia Bargou Ltd, CE Hammamet Ltd and CE Nabeul Ltd were inactive during the current and prior year, therefore the Financial Statements
of the consolidated entity also represent the closed group results. These entities were also wound up during the financial year.
110
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 23. Investments in controlled entities continued
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.
24. Parent entity information
Information relating to the parent entity, Cooper Energy Limited
Current Assets
Total Assets
Current Liabilities
Total Liabilities
Issued capital
Accumulated loss
Option premium reserve
Share based payment reserve
Total shareholders’ equity
Loss of the parent entity
Total comprehensive loss of the parent entity
Other Information
25. Commitments for expenditure
2021
$’000
405,709
616,747
17,695
185,623
477,675
2020
$’000
114,686
638,485
14,891
192,562
475,862
(61,655)
(42,794)
25
15,079
431,124
(18,862)
(18,862)
25
12,830
445,923
(39,302)
(39,302)
The Group has the following commitments for expenditure not provided for in the financial statements and payable.
Due within 1 year
Due within 1-5 years
Due later than 5 years
Total
Exploration capital
Leases
2021
$’000
2,460
63,445
-
2020
$’000
32,300
68,944
-
65,905
101,244
2021¹
$’000
8,151
244,535
84,683
337,369
1. Commitments relating to leases that have not yet commenced.
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 2021 the Parent entity has bank guarantees for $8.8 million (2020: $1.5 million). These guarantees are in relation to credit
support for gas purchases and guarantees on office leases.
2020²
$’000
24,273
242,729
112,398
379,400
111
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 26. 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.
27. Share based payments
At the 2018 AGM, shareholders of Cooper Energy approved the plan referred to as the Equity Incentive Plan (EIP). Performance rights and
share appreciation rights were issued for no consideration under the EIP. These rights issued will 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 in the 90th percentile or higher 100% of the eligible rights will vest.
Performance rights are also granted as part of deferred STIP and 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:
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
Date Granted
12 December 2018
11 December 2019
11 December 20191,2
13,312,848
14,871,802
-
10 December 2020
20,473,191
10 December 2020²
-
1. Granted in December 2019 and exercised in December 2020
2. Relates to deferred STIP performance rights granted
4,888,166
4,257,209
769,605
6,394,202
1,885,834
$0.435
$0.575
$0.575
$0.390
$0.390
3
3
1
3
1
0.5
1.5
-
2.5
0.5
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 following employee termination
Balance at end of year
Achieved at end of year
1. Includes deferred STIP issued as performance rights
Number of Share
Appreciation Rights
Number of Performance
Rights1
2021
48,280,025
20,473,191
(6,438,631)
(4,881,179)
-
2020
38,457,469
14,871,802
2021
17,862,629
8,280,036
2020
15,464,897
5,026,814
(5,049,246)
(3,333,247)
(2,613,107)
-
-
(1,889,863)
-
-
(15,975)
57,433,406
48,280,025
20,919,555
17,862,629
-
-
-
-
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.
112
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 27. Share based payments continued
Share Appreciation Rights fair value assumptions
Fair value at measurement date
Share price
Risk free interest rate
Expected volatility
Dividend yield
Performance Rights fair value assumptions
Fair value at measurement date
Share price
Risk free interest rate
Expected volatility
Dividend yield
Accounting Policy
12 December
2018
11 December
2019
10 December
2020
14.5 cents
43.5 cents
1.95%
49%
0%
15.8 cents
57.5 cents
0.68%
40%
0%
10.9 cents
39.0 cents
0.11%
45%
0%
12 December
2018
11 December
2019
10 December
2020
30.0 cents
43.5 cents
1.95%
49%
0%
37.7 cents
57.5 cents
0.68%
40%
0%
25.6 cents
39.0 cents
0.11%
45%
0%
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 impact of dilution, the non-tradable nature of the performance
right or share appreciation right, the share price at grant date, the expected price volatility of the underlying share, the expected dividend yield
and the risk-free interest rate for the term of the vesting period. The fair value of the performance rights and share appreciation rights granted
excludes the impact of any non-market vesting conditions (for example, profitability and sales growth targets).
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:
1. the extent to which the vesting period has expired; and
2. the Group’s best estimate of the number of equity instruments that will ultimately vest.
No adjustment is made for the likelihood of market performance conditions being met as the effect of these conditions is included in the
determination of fair value at grant date. The Consolidated Statement of Comprehensive Income charge or credit for a period represents the
movement in cumulative expense recognised as at the beginning and end of that period.
No expense is recognised for awards that do not ultimately vest, except for awards where vesting is only conditional upon a market condition.
If the terms of an equity-settled award are modified, as a minimum an expense is recognised as if the terms had not been modified.
In addition, an expense is recognised for any modification that increases the total fair value of the share-based payment arrangement,
or is otherwise beneficial to the employees as measured at the date of modification.
If an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation, and any expense not yet recognised for the
award is recognised immediately. However, if a new award is substituted for the cancelled award and designated as a replacement award on
the date that it is granted, the cancelled and new award are treated as if they were a modification of the original award, as described in the
previous paragraph.
The dilutive effect, if any, of outstanding performance rights and share appreciation rights is reflected as additional share dilution in the
computation of diluted earnings per share.
Significant Accounting Judgements, Estimates and Assumptions
The Group measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments at the date
at which they are granted. The fair value is determined by an external valuation expert using the calculation criteria.
113
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021
28. Related party disclosures
The Group has a related party relationship with its joint arrangements (Note 22), its subsidiaries (Note 23), and its key management personnel
(disclosure below).
The key management personnel’s remuneration included in General Administration (see Note 2) is as follows:
Short-term benefits
Other long-term benefits
Post-employment benefits
Performance Rights and Share Appreciation Rights
Total
29. Remuneration of Auditors
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
Taxation and other services
Total fees to Ernst & Young
2021
$
2020
$
4,818,430
5,906,298
54,545
251,556
47,513
244,725
2,123,212
2,263,996
7,247,743
8,462,532
2021
$
2020
$
486,075
486,075
48,300
48,300
534,375
511,395
511,395
187,915
187,915
699,310
30. Events after the reporting period
Other than the Sale and Purchase Agreement for the sale to Bass Oil of the Company’s interests in several of its Cooper Basin exploration and
production licenses (PEL 93, PPL 207, PRL 237, PEL 100 and PEL 110) that was announced on 12 July 2021 as detailed in Note 10, there are no
significant events subsequent to 30 June 2021 at the date of this report. .
114
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the year ended 30 June 2021COOPER ENERGY ANNUAL REPORT 2021 Directors’ Declaration
In accordance with a resolution of the Directors of Cooper Energy Limited, I state that:
1. In the opinion of the Directors:
DIRECTORS’ DECLARATION
(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 2021 and of its
In accordance with a resolution of the Directors of Cooper Energy Limited, I state that:
performance for the year ended on that date; and
1.
In the opinion of the Directors:
(ii) complying with Australian Accounting Standards (including the Australian Accounting Interpretations) and the
(a) the financial statements and notes of the consolidated entity are in accordance with the Corporations Act 2001, including:
Corporations Regulations 2001;
(i) giving a true and fair view of the consolidated entity’s financial position as at 30 June 2021 and of its performance for the year ended
(b) the financial statements and notes also comply with International Financial Reporting Standards as disclosed in the
on that date; and
Basis of Preparation; and
(ii) complying with Australian Accounting Standards (including the Australian Accounting Interpretations) and the Corporations Regulations
(c) there are reasonable grounds to believe that the Company will be able to pay its debts as and when they become
2001;
due and payable.
(b) the financial statements and notes also comply with International Financial Reporting Standards as disclosed in the Basis of Preparation;
2. This declaration has been made after receiving the declarations required to be made to the Directors in accordance
and
with section 295A of the Corporations Act 2001 for the financial year ended 30 June 2021.
(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.
3. In the opinion of the Directors, as at the date of this declaration, there are reasonable grounds to believe that the
2. This declaration has been made after receiving the declarations required to be made to the Directors in accordance with section 295A of the
members of the Closed Group identified in note 23 will be able to meet any obligations or liabilities to which they are,
Corporations Act 2001 for the financial year ended 30 June 2021.
or may become subject, by virtue of the deed of cross guarantee.
3.
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 23 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.
Signed in accordance with a resolution of the Directors.
Signed in accordance with a resolution of the Directors.
Mr John C. Conde AO
Mr John C. Conde AO
Chairman
Chairman
23 August 2021
23 August 2021
Mr David P. Maxwell
Mr David P. Maxwell
Managing Director
Managing Director
115
COOPER ENERGY ANNUAL REPORT 2021
116
COOPER ENERGY ANNUAL REPORT 2021 117
COOPER ENERGY ANNUAL REPORT 2021 118
COOPER ENERGY ANNUAL REPORT 2021 119
COOPER ENERGY ANNUAL REPORT 2021 120
COOPER ENERGY ANNUAL REPORT 2021 121
COOPER ENERGY ANNUAL REPORT 2021 122
COOPER ENERGY ANNUAL REPORT 2021 Securities Exchange and Shareholder Information
as at 31 August 2021
Listing
The company’s shares are quoted on the Australian Securities Exchange under the code of “COE”.
Number of Shareholders
There were 9,422 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 2021)
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
100,001 - 9,999,999,999
Total
Unquoted Options on Issue Nil
Unquoted Performance Rights
Number of Holders of Rights
101
22
1,035
2,372
1,430
3,729
856
9,422
294,429
6,677,245
11,793,671
140,693,469
1,471,567,291
1,631,026,105
0.02
0.41
0.72
8.63
90.22
100.00
Total Performance Rights
20,435,120 Performance Rights
56,443,748 Share Appreciation Rights
Unmarketable Parcels
There were 2,026 members, representing 1,913,049 shares, holding less than a marketable parcel of 2,223 shares in the company.
Twenty Largest Shareholders
Rank Name
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
HSBC Custody Nominees (Australia) Limited
J P Morgan Nominees Australia Pty Limited
Citicorp Nominees Pty Limited
CS Third Nominees Pty Limited
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