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Investing for increased gas supply
Annual
Report 2020
Cooper Energy
We energise the lives of thousands of
Australians everyday by finding, developing
and commercialising oil and gas.
We do this with care and strive to provide
attractive returns for our shareholders; good
commercial outcomes for our customers;
and benefits for our stakeholders.
Cooper Energy Limited
ABN 93 096 170 295
Cover: Athena Gas Plant.
Information on descriptions of the company and years, abbreviations and industry terms.
The terms “the company” and “Cooper Energy” are used in the report to refer to Cooper Energy
Limited and/or its subsidiaries. The terms “2020”, “FY20” and the “2020 financial year” refer to
the 12 months ended 30 June 2020 unless otherwise stated. Likewise references to 2019, FY19
or 2021, FY21 refer to the 12 months ending 30 June of that year.
This Report uses terms and abbreviations relevant to the Group, its accounts and the petroleum
industry. Information on abbreviations and terms, rounding and reserves and resources
reporting is provided on page 128.
Our values and what they mean.
We have chosen to be a values-driven business.
We strive to think, decide and act at all times
in accordance with our seven core values:
Care: prioritising safety, health, the environment and community
Integrity: striving to be consistent; staying true to our values
and being 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 core objectives;
making pragmatic, quality technical and commercial decisions;
and being decisive with the courage of our convictions
1
Our business
We generate revenue from the discovery,
commercialisation and sale of gas to south-east
Australia and from cash generating Cooper Basin
oil production.
We have purpose-built our portfolio to provide attractive returns for
our shareholders and good commercial outcomes for our customers by
selecting assets that:
• possess superior competitiveness for the supply of gas to market;
• are in production or expected to be ready for a development decision
within 5 years; and
• are value accretive.
FY20 Production
1.56 MMboe
Proved and Probable Reserves
49.9 MMboe at 30 June 2020
Contingent Resources (2C)
34.9 MMboe at 30 June 2020
0.20
0.34
1.6
9.5
0.8
8.5
1.02
38.8
25.5
Otway gas
Sole gas
Cooper Basin oil
Otway Basin gas
Otway Basin gas
Gippsland Basin gas and gas liquids
Gippsland Basin gas and gas liquids
Cooper Basin oil
Cooper Basin oil
Other key statistics:
As at 30 June 2020
Market capitalisation:
Net debt:
Issued shares:
Shareholders:
$608 million
$97.8 million
1,621.6 million
8,094
Employees and contractors:
107.4 full time equivalent
2
1. Offshore Otway Basin:
2. Gippsland Basin:
Gas production and exploration
• Casino Henry Netherby gas production and development
Offshore gas production and exploration
• Sole gas field
• Annie gas field
• Gas exploration
• Manta gas and liquids resource
• Exploration permits
Darwin
5
Brisbane
Perth Office
Adelaide Office
Sydney
4
3
1
Melbourne
2
Hobart
3. Athena Gas Plant:
Gas processing for offshore Otway Basin
• Being commissioned for commencement of
operations in September Quarter 2021
4. Onshore Otway Basin:
5. Cooper Basin:
Gas exploration
• Gas exploration
Onshore oil production
• Western flank oil production and exploration
3
Key results
Financial
• Sales revenue up 3% to $78.1 million due to higher revenue from gas
• Statutory loss after tax of $86.0 million after significant items of $79.4 million
• Underlying loss after tax of $6.6 million
• Cash generated by operating activities up 134% to $48.1 million
Sales revenue
$ million
Statutory net profit after tax
$ million
Underlying net profit after tax
$ million
78.1
75.5
67.5
39.1
27.4
27.0
-12.3
-12.1
-34.8
-86.0
13.3
9.8
-2.8
-8.7
-6.6
2016
2017
2018
2019
2020
2016
2017
2018
2019
2020
2016
2017
2018
2019
2020
Net cash from operating activities
$ million
Net cash/(debt)
$ million
Total equity
$ million
48.1
147.4
111.0
49.8
443.9
433.7
351.1
285.0
91.6
-53.9
-97.8
22.2
20.5
7.9
4.1
2016
2017
2018
2019
2020
2016
2017
2018
2019
2020
2016
2017
2018
2019
2020
4
Operations and reserves
• One lost time injury
• Production up 19% to 1.56 MMboe
• Sole offshore project completed, production commenced,
firm supply delayed pending plant completion
• Gas exploration successful with Annie and Dombey gas discoveries
Safety
Lost time injury frequency rate
Production
MMboe
Proved and Probable reserves
MMboe
3.53
1.49
1.56
1.31
52.4
52.7
49.9
0.96
0.46
0.0
0.0
0.0
11.7
3.0
2016
2017
2018
2019
2020
2016
2017
2018
2019
2020
2016
2017
2018
2019
2020
Equity
Share price
cents at 30 June
54.0
38.0
38.5
37.5
21.5
Basic earnings per share
cents
Market capitalisation
$ million at 30 June
1.8
-0.7
-1.8
876
616
608
-5.3
433
2016
2017
2018
2019
2020
2016
2017
2018
2019
2020
2016
2017
2018
2019
2020
-10.1
94
5
Overview of operations
Gas supply
Sales rose because Sole started
production.
Outcomes below expectations
due to late and incomplete Orbost Gas
Processing Plant commissioning.
Oil production
Cash generating oil production.
Gas sales PJ
Gas revenue $ million
Gas reserves Proved and Probable PJ
2020
2019
8.3
63.6
296
6.6
52.3
311
Crude oil & condensate production million bbl
Crude oil revenue $ million
Average oil price A$/bbl
2020
2019
0.20
14.5
0.24
23.2
83.75
102.52
Crude oil direct operating cost A$/bbl
35.17
36.45
Crude oil reserves Proved & Probable
million barrels
1.6
1.8
• Gas sales revenue rose 22%
• Completion of largest oil drilling campaign
• New gas agreements negotiated for supply
to Visy and Visy Glass International
• Sole term supply contracts deferred
to FY21 pending Orbost Gas Processing
Plant commissioning
involving 16 wells: 2 exploration wells,
13 appraisal wells and 1 development
• 3 appraisal wells cased and suspended as
future oil producers
Gas contract book by term
PJ
Gas supply by source
PJ
3
2.1
6.2
6.6
2019
2020
Otway
Gippsland
115
150
28
Contracted 1 year or less
Contracted >3 years
Subject to extension options
Uncontracted
6
Exploration and
Development
Sole offshore development completed
within budget.
Annie and Dombey gas discoveries.
Health, Safety, Environment
and Community
Single Lost Time Injury.
Bushfire recovery support and broader
community engagement.
Commitment to carbon neutrality for
2020 operations.
Capital expenditure $ million
Proved and Probable reserves MMboe
Contingent Resources (2C) MMboe
Wells drilled
2020
2019
76.7
49.9
34.9
18
200.0
Hours worked
Recordable incidents
Lost time injuries
52.7
26.9
0
2020
2019
283,672
505,300
1
1
0
0
• Sole offshore project completed for $335 million
• Single lost time injury
vs budget $355 million
• Acquisition of Minerva Gas Plant, renamed
Athena Gas Plant
• Final Investment Decision on Athena Gas Plant
Project in July 2020
• New gas field discoveries offshore and
onshore Otway
• Zero reportable environmental incidents
• Participation and ongoing support for
East Gippsland bushfire recovery
• Commitment to carbon neutral operations
for 2020
• Effective strategies implemented to prevent
COVID transmission
2020 Capital expenditure
by activity $ million
2020 Capital expenditure
by region $ million
4
11
35
42
44
18
Exploration
Development
Otway Basin
Gippsland Basin
Cooper Basin
Other
7
From the Chairman
John Conde AO
I am pleased to present
Shareholders can take confidence in the competence Cooper Energy
your company’s report
has demonstrated in its core business of offshore gas development.
to shareholders for the
2020 financial year.
The success of the year’s drilling program yielded gas discoveries
and increased the company’s Contingent Resources in the
The period since 1 July
offshore and onshore Otway Basin. The new discoveries, at Annie
2019 has been one of
and Dombey, are being analysed for development or further
enormous challenge for
exploration. The securing of new acreage adjacent to these
Australia and the world.
discoveries, and in the Gippsland Basin, has consolidated the
The Australian
bushfires followed by
company’s portfolio around proven gas provinces and established
infrastructure located close to the key gas markets.
the COVID-19 global
Cooper Energy’s gas strategy has been well publicised and proven
pandemic, considered to
prescient. The generation of value from the strategy depends
be without precedent, have had a huge impact on the markets
on other factors including the quality of commercial analysis,
and communities in which we operate.
the capacity to establish and maintain win-win commercial
On behalf of the board, I record our recognition and sympathy
relationships and the aptitude for finding and securing value.
for the personal, property or financial losses the recent local and
Your company’s results in 2020 have once again highlighted Cooper
global events have brought to people connected to our company.
Energy’s commercial capabilities with outcomes expected to be of
Care, collaboration, fairness and respect, and commitment are four
of the seven core values that Cooper Energy seeks to embrace in
all of its decisions. These values underpin our efforts to support our
people and communities through their recovery.
The fires, the pandemic and an unforeseen project delay have
affected adversely the company’s results for 2020. However,
although our results for the year were well below our expectations
at the start of the year, we feel that we ended the financial year with
a strong closing position. Our asset base and outlook will support
growth in FY21 and the following years.
long-term significance. These included securing new gas supply
agreements and acquisition of the Minerva Gas Plant. The support
and cooperation of valued counterparties facilitated management
of our gas contract portfolio amidst the shifting start-up timelines
brought by the delay of the Orbost Gas Processing Plant.
Secondly, I highlight our health and safety performance. Results
were inferior to the previous year, with one lost time injury
compared with the injury-free performance in FY19. This was one
injury too many and, for this reason, is an unsatisfactory result.
However, there were positive elements that are noteworthy and
provide relevant context: for all assets under our own control and
The Managing Director’s Report and the Financial Report address
management the company maintained safe operations, the lost
these matters in detail. The 2020 Sustainability Report, which has
been published alongside this report, documents the company’s
performance, disclosures and objectives in respect of health and
safety, environment, climate, community and its people.
time injury having occurred on a contractor vessel on location,
but not, at the time, under the direction of Cooper Energy. The
company’s recordable incident frequency rate of 3.53 times per
million hours worked compares favourably to the industry average 1
There are three features from these documents to which I draw
of 5.27 times.
particular attention.
First, the company’s performance on the matters where it has
direct responsibility.
The offshore development, construction and commissioning of
the Sole Gas Project was completed by Cooper Energy well within
budget, on time and with zero lost time injuries or reportable
environmental incidents. This is an exceptional performance.
COVID-19 added a new dimension to the company’s safety
management. As an energy supplier, Cooper Energy continued
operations, with work arrangements at site, office and board levels
all reconfigured to guard the health of employees and contractors
and protect busines continuity. The board continued to meet and
work effectively via video-conference facilities. The fluidity of social
distance and health regulations required a proactive and adaptive
response and your company is vigilant and maintaining readiness
Unfortunately, our excellent offshore performance has been over-
for further developments.
shadowed by the delay to the completion onshore of the Orbost
Gas Processing Plant which is owned and operated by APA Group.
1 National Offshore Petroleum Safety and Management Authority.
8
Thirdly, I highlight the company’s commitment to achieving carbon
I record my thanks to all my board colleagues and to our Company
neutrality.
Cooper Energy has long maintained its commitment to operating
with care for the environment as one of our core values.
Engagement with our shareholders has confirmed their belief
in the importance of south-east Australian gas for the region’s
energy needs. It has also highlighted a deep and widely held
conviction that companies should play their part in understanding,
Secretary for their counsel and support in what has been a
demanding year. In May, we welcomed Ms Vicky Binns and Mr Tim
Bednall to the board, subject to confirmation by shareholders at
this year’s annual general meeting. Each of these new directors
brings valuable expertise to the board. We are fortunate to have
their support and insights as we address the challenges to which
I have referred earlier.
and seeking to reduce, the impact of their activities on climate
I acknowledge especially the contribution of my fellow non-
and the environment. This year’s Sustainability Report outlines
executive director Ms Alice Williams who is not seeking re-election
your company’s progress. Most significant is our commitment to
at the forthcoming AGM. Alice has been a valued member of the
carbon neutrality for 2020 and to work to achieve this objective in
board and has been part of the company’s significant growth,
future years. Cooper Energy wants to play its part and is working
contributing always to discussions. Alice has been Chairman of our
to ensure ongoing improvement in the management of its
Audit Committee for nearly seven years. She is a person of great
integrity and loyalty, with an almost forensic ability to ensure that
the financial affairs of the company were conducted always to the
highest standard. On behalf of us all, thank you Alice.
Finally, I record our appreciation to our Managing Director,
David Maxwell, and all his team for their leadership during very
challenging times and to the entire Cooper Energy team for their
work and support.
John Conde AO
Chairman
environmental impacts.
Concluding comments and outlook
This report has been finalised some six months after the first
impacts of COVID-19 on all of us and on the Australian economy.
As is evident in the company’s FY20 accounts, the energy sector
has experienced contraction of demand and prices, but it is also
poised for the eventual recovery in consumer confidence and
economic activity.
The timing and rate of this recovery is unknown, but Cooper Energy
is well placed to navigate and grow during this uncertainty.
The majority of the company’s gas reserves are subject to long
term contracts, offering stable cash flows through take-or-pay
terms and prices not linked to oil prices. Cooper Basin oil provides
an additional source of cash flow from low cost production. The
commencement of term gas supply from Sole, deferred in FY20,
is expected to drive substantial growth in production, revenue and
cash generation in FY21. Cash at 30 June was $131.6 million and
capital expenditure plans are manageable as the company prepares
for a resumption of offshore drilling on new gas projects in FY23.
Underpinning these fundamentals are the company’s relationships,
especially with its gas customers and financiers but also with the
communities in which we operate and with relevant government
regulators and other stakeholders. These relationships were
fundamental to the Sole Gas Project proceeding. The board is
cognisant and appreciative of the solidarity and commitment our
customer and banking groups have shown us this year, supporting
our strategy to bring new term gas supply to south-east Australia.
9
Managing Director’s Report
David Maxwell
Fellow shareholders,
Whilst an injury-free performance is the only acceptable result, I do
Your company’s results
for the 2020 financial
year were not what we
expected at its outset.
The promising start
given by successful
completion of the Sole
offshore development,
gas discoveries offshore
and onshore and new
gas contracts was ultimately overshadowed by non-completion of
the Orbost Gas Processing Plant upgrade and the impact of low
wish to acknowledge the efforts of our employees and contractors
in restricting injuries to this single incident. A safe record is only
achieved through the planning and vigilance of every employee, at
every location, in every moment of the working year. On behalf of
shareholders and the board of directors, I record our appreciation
for their contribution to safe operations by Cooper Energy.
The COVID-19 pandemic brought new dimensions to care for
employee health and safety. Cooper Energy was an early responder
in adopting working protocols and arrangements to protect its
employees and maintain business continuity. The company’s
efforts have been well supported by government agencies and the
independent advisors we commissioned to guide our efforts.
oil prices and of Coronavirus-19 (COVID-19) on energy markets.
As an essential service, energy supply has not been directly
These events resulted in the year’s production and cash flow
affected by restrictions although, as I have noted in my opening
outcomes being much lower than anticipated and contributed to
and discuss later, there has been a significant financial impact
the impairments which affected statutory profit.
through flow-on impacts to energy markets and prices. The
Discussion of these events and their significance is an important
part of my report to you this year, together with our performance
and plans in safety, environment, new projects and the status and
outlook of our gas strategy.
Notwithstanding that your company did not achieve the production
and financial results targeted at the year’s outset, it has concluded
2020 with record production and revenue. The company has more
growth assets in its portfolio, firm expectation of a step-change
uplift in production and cash flow and a stronger position in the
south-east Australian gas market.
company’s unmanned subsea gas production is unaffected by
restrictions, and office-based work continued through work-from-
home and then revised socially distanced office configurations.
Care and maintenance of the Athena Gas Plant has been ongoing
using a skeleton crew and safe work practices.
Participation in the regional communities where our operations
are located is an integral element of our business model. One of
these communities, East Gippsland, suffered great tragedy during
the year from extensive bushfires. I record our sympathy for the
loss experienced by the East Gippsland community, which included
loss of human life, wildlife and farm stock as well as property and
Health, safety, environment and community
financial loss. Cooper Energy provided financial support and direct
Operating with care is the first Cooper Energy value and the
governing principle of our day-to-day activities and decision-making.
help in organising logistics for supply of feed to farm animals
immediately after the bushfires. The company has also committed
to ongoing support for the communities in what will be a long-
We have detailed our performance and impacts in the 2020
term recovery process.
Sustainability Report, which has been released in parallel with
this report and is available from the company’s website. There are
three aspects I wish to highlight in this report: safety and health,
community and climate.
The measurement, disclosure and management of emissions has
become a core concern for the community and investors. For
Cooper Energy this requires us to understand and manage the
delivery of energy required by the domestic, industrial, service and
Our safety performance in 2020 fell just short of the injury-free
commercial sectors whilst respecting the desire of our shareholders,
standard we aspire to, and which was achieved in 2019. A lost
employees and broader society for emissions reduction.
time injury was recorded on the Ocean Monarch drilling rig whilst
on location at VIC/P44 for the drilling of Annie-1. Thankfully the
injured worker, who was employed by the drilling contractor,
recovered and returned to work. The fact the injury was incurred
whilst the rig was not under the supervision of Cooper Energy at
the time reinforces the need for vigilance across the widest extent
of our operations.
10
Gas has been identified by government and energy industry
agencies as having a necessary role to play, as a lower carbon fuel,
in the transition to a lower emissions world. In addition, Cooper
Energy wants to play its part in emissions reduction directly.
Accordingly we have, as detailed in the 2020 Sustainability Report,
made the commitments for the achievement of carbon neutrality
in respect of our 2020 operations and to work to achieve the same
outcome in future years.
Subsea 7 contractors inspecting flowline as it is
spooled onto the construction vessel, Seven Eagle.
I encourage shareholders to read the 2020 Sustainability Report
construction and disruption brought by the East Gippsland
to learn of the work the company is doing to promote safety,
bushfires. Unexplained foaming has impaired the capacity of
health and environment outcomes connected to its operations and
the plant to produce at the level required for commissioning to
advance diversity. The report can be read or downloaded from the
be completed and for firm supply to commence. The impact
company’s website www.cooperenergy.com.au.
on Cooper Energy was that gas sales from Sole during the year
Sole Gas Project
were approximately 2 PJ at spot gas prices rather than the
12 PJ under term gas contracts anticipated at the beginning of the
The completion of the offshore development of Sole in July was
financial year.
the culmination of more than 4 years of work by your company
to analyse, acquire and then finance and develop the field. The
offshore development was completed and commissioned injury-
free, and well within budget. Final capital expenditure on the
offshore project was $335 million compared with the budget of
$355 million. Offshore production facilities and the reservoir have
performed to expectations since production commenced.
Unfortunately, delays with the onshore project managed by
APA Group have necessitated deferral of the commencement of the
long-term gas supply agreements, rescheduling of events within
the company’s financing agreements and, ultimately, a Transition
Agreement with APA to facilitate progress to the commencement
of firm supply.
Gas supply from the field commenced in March for plant
commissioning purposes, a date significantly later than
foreshadowed in the 2019 annual report due to delays in plant
The Transition Agreement executed after year-end by Cooper
Energy and APA unites both parties in identifying and overcoming
the plant performance issues and generating revenue at the earliest
juncture. The commercial framework of the agreement provides
for the commencement of firm supply to Cooper Energy long-term
customers in advance of plant practical completion at rates the
plant is capable of supplying reliably.
Cooper Energy and APA are working together to identify the
root cause of the foaming and explore and implement technical
solutions to lift performance to the required level. This includes
Phase 2 plant works being planned for the December quarter 2020.
The intended outcome is for Cooper Energy to be able to
commence firm gas supply from Sole to customers within FY21
with the expectation achievement of higher processing rates will be
targeted incrementally following the Phase 2 plant works.
11
Managing Director’s Report
David Maxwell
Financial results and position
The company’s financial results, position and operating results
are reported in detail in the Financial Report from page 35 of
this report.
The year’s statutory loss after tax of $86.0 million is principally
attributable to significant items totalling $(79.4) million after tax,
most of which arose from a review of asset carrying values and
restoration provisions expensed at year-end.
It is important to note these items have not arisen through trading
and have not impacted the year’s cash flow. The charges have
Exploration and development, projects
for growth
Since 2015 the company’s principal focus has been on the
commercialisation and development of the Sole gas field. With
the Sole offshore development complete, the focus shifted to the
addition of new growth assets to the company’s gas portfolio.
The $42 million commitment to exploration in FY20 was the largest
yet by the company and resulted in the Annie gas discovery in
the offshore Otway Basin and the Dombey gas discovery in the
onshore Otway Basin.
essentially been driven by two factors: revisions to uncontracted
Annie is located near the Casino, Henry and Netherby gas fields
gas price assumptions to recognise the lower energy prices and
and associated infrastructure. The assessment of a Contingent
lower energy demand brought by COVID-19; and revisions to
Resource (2C) for the field was the principal factor in the 33%
anticipated development and abandonment costs following the
rise in the company’s 2C Contingent Resources of gas at 30 June
FY20 drilling campaign, updated prices and regulatory expectations
2020. Commercialisation of the Annie gas field is being assessed
and the recognition of foreign exchange and government bond
as part of the Otway Phase 3 Development Project, which aims
rate movements.
The fall in gas prices during FY20 was substantial: as an indication,
the average Victorian spot price for the month of June 2020 of
to bring more than 100 PJ of gas (joint venture volume, Cooper
Energy share is 50%) to market through development of Annie and
undeveloped gas in the Henry gas field.
$4.62/GJ was approximately half the average of $9.41/GJ for the
Annie-1 was intended, as reported in last year’s annual report,
previous corresponding period. The adoption of 2020 prices and
to be the first of a 2-well program in the offshore Otway Basin.
expectations to valuation of the company’s uncontracted gas and
Unfortunately, the second well in the program, Elanora, could
projects required impairment to the carrying value of some assets.
not proceed due to unresolved issues with the drilling rig
Notwithstanding the year’s lower prices, I note that developments
mooring system.
during the year (which I discuss later under the heading “Gas
strategy update”) have affirmed the merit of the company’s gas
strategy and the prospects for our uncontracted gas in the
coming years.
Energy market analysis conducted during the year has highlighted
the market prospects of new gas supply to south-east Australia
from 2023 onwards. This market opportunity, combined with the
findings of subsurface and economic analysis of the prospects in
The year’s underlying loss of $6.6 million for the year compares
our offshore Otway permits presents a compelling case for further
with an underlying profit of $13.3 million in the previous year.
drilling. Testing of Elanora, together with several other offshore
The movement is consistent with a year when an increase in costs
Otway prospects, is being considered for an offshore campaign
consistent with the development of the business’ asset base was
being planned to commence in the first half of FY23, subject
not matched by the anticipated growth in revenue due to the
to rig availability.
deferral of Sole term gas supply commencement. These additional
costs included the commencement of expenses related to the
Sole offshore development following its completion, such as
amortisation and interest on the project finance facility, which had
been previously capitalised.
The company has concluded the year with net debt of $97.8 million,
which comprises cash of $131.6 million and debt of $229.4 million.
The debt is within the project finance facility established with
The company’s portfolio of offshore Otway exploration
opportunities was expanded with the acquisition of VIC/P76 during
the year. VIC/P76 is well situated for Cooper Energy, with its eastern
border adjoining VIC/L22, which contains the Minerva gas field,
and its western border adjoining VIC/P44 where the Annie gas
field was discovered. A small portion of the Annie gas field has
been mapped to extend into VIC/P76, which also holds other gas
prospects including Nestor, a low risk gas exploration opportunity
senior banks to fund the company’s expenditure for the Sole Gas
similar to Annie.
Project. The delay to completion of the Orbost Gas Processing
Plant has necessitated rescheduling of milestone dates for the
facility. Cooper Energy has maintained dialogue with its financiers
who have reiterated their support for the project. It is expected a
schedule of revised milestone dates will be agreed with financiers
during the first half of FY21 after the plans for the Phase 2 plant
works are finalised.
Dombey-1 made a gas discovery in the onshore Otway Basin.
Although initial good flow rates on test were not sustained, the
subsequent re-pressurisation of the reservoir gives encouragement
for a larger gas accumulation than the test results initially indicated.
The well also de-risked and highlighted potential in the broader
Penola Trough region. We expect to conduct further exploration
through acquisition of 3D seismic and follow-up drilling in this
region in the coming years. The timelines involved are medium term;
12
Athena Gas Plant
but consistent with our strategy, the fundamentals are right: the
Our focus is on south-east Australia, where the supply
onshore Otway Basin is a proven gas province, with existing gas
opportunities we identified in 2012 led to the commercialisation of
infrastructure, nearby markets and the development cost threshold
the Sole gas field and where we see new opportunities emerging
is very cost competitive.
from 2023 onwards.
The acquisition of the Minerva Gas Plant was the other significant
The Sole project is illustrative of our approach: early identification
growth initiative for the year. Upgrading and integration of the
and analysis of a future supply opportunity, followed by the securing
plant will be the company’s major development expenditure item
and commercialisation of an undeveloped gas field identified as
in FY21. Once connected, the Athena Gas Plant (as it has been
a competitive source of new supply. The commercialisation of
renamed) will be the hub for our offshore Otway operations.
Sole was enabled by the support of gas customers, financiers and
Connection of the plant to our gas operations is expected to be
completed in the September quarter 2021, although this is subject
to the threat of disruption to supply chain or restrictions arising
investors, and APA Group and their collective willingness to join the
company in making commitments necessary to bring a new source
of gas supply to market.
from COVID-19. Athena is expected to bring lower processing
Market developments in 2020 adversely affected short term gas
costs, higher productivity and, most importantly, a processing hub
prices, signalled tightening gas supply from 2023 and reaffirmed
with capacity for discoveries such as Annie. The plant’s location in
the merit of the company’s gas strategy and the prospects for its
western Victoria is also ideally suited for supply to South Australia
undeveloped gas.
and Victoria.
Gas strategy and market update
Cooper Energy aims to create value from gas through management
of a portfolio of gas supply contracts and production sources to
optimise returns to shareholders.
The weakening of international energy demand and prices brought
by the Coronavirus pandemic had flow-on effects to spot prices
for domestic gas and will impact long-term supply. Low LNG spot
prices saw an increase in gas flows from Queensland to south-east
Australia, increasing domestic supply availability and reducing
spot prices. Exploration and development spending was also
curtailed. It is expected the soft spot prices will persist into FY21.
13
Managing Director’s Report
David Maxwell
However, government projections (Australian Energy Market
This has been advanced during the year by the discovery of the
Operator, “AEMO”) issued during the year have forecast an
Annie gas field, securing of adjoining exploration acreage, the
inversion of market dynamics for south-east Australia within two
progression of development studies for Annie and undeveloped
to three years as local production falls. AEMO’s forecast, and
Henry gas, the planning of the Manta-3 appraisal and development
the company’s own analysis, sees new gas supply opportunities
well and analysis and the ranking of exploration prospects for a
emerging from 2023 as production from currently producing fields
drilling program anticipated in FY23. Our portfolio features
declines. Moreover, these analyses, prepared earlier in the year, do
a range of exploration, development and appraisal opportunities
not incorporate the negative impact on supply to be expected from
with maturation timelines that dovetail neatly with the market
the subsequent reductions to capital expenditure in 2020 and 2021.
opportunities foreseen in south-east Australia.
The questions these developments present for Cooper Energy and
FY21 outlook
its gas strategy are:
a) how is the company placed to manage exposure to the soft
market conditions of FY20 and expected for FY21 ? ; and
b) how is the company positioned to capitalise on the opportunities
foreseen from FY23 onwards?
In respect of the near term, the benefits of the company’s strategy
of maintaining a ‘long’ contract book is evident.
The company’s principal source of gas production, Sole, has almost
fully contracted term contract capacity to 2025. The delays with the
Orbost Gas Processing Plant completion mean the company has
not yet commenced these term contracts and has been supplying
available Sole production at current spot prices. The initiation of
the term supply contracts is targeted for by around mid-FY21
after establishment of a firm supply capability at the Orbost Plant.
From this point on, the large majority of sales are expected to be
at the term gas contract prices previously negotiated.
Most of the company’s uncontracted 2P gas reserves are located
in the Otway Basin, where contracting terms have been affected
by the company’s reliance on third party processing capability.
This situation will change with the completion of the Athena Gas
Plant Project, which will give the company access to firm supply
capability for the remaining life of the producing fields.
Approximately 1 PJ of the company’s Otway Basin production has
been contracted for 2021. The company is currently considering
its options for the contracting of its uncommitted gas prior to the
anticipated commencement of supply from the Athena Gas Plant
and in the years thereafter. Our portfolio-style management of gas
contracts provides some optionality between Otway and Gippsland
basin supply.
Looking to the longer term, the opportunity to bring new
south-east Australian gas supply to market from 2023 has been
a key strand in the company’s gas strategy since 2018 when
preparations began for the offshore Otway drilling program and
the commitment made to acquire the Minerva Gas Plant.
There are 2 principal points of focus in our new year outlook:
• Sole in the Gippsland Basin from where we expect to realise uplift
in production, revenue and cash flow in FY21. The quantum of
production growth will be dependent on at least two milestones
for the Orbost Gas Processing Plant: the commencement of firm
supply and the consequent initiation of the term gas supply
contracts; and
• the offshore Otway Basin, where our work on the Athena Gas
Plant Project and new development opportunities provides us
with a dedicated processing facility and new gas projects for
growth in future years.
While the delays of the previous year have been frustrating,
I can assure shareholders your company’s team is eager to deliver
production, revenue and cash earnings gains in FY21 and to
translate the opportunities within its portfolio into new sources
of gas supply to south-east Australia and the next wave of growth
for Cooper Energy.
In closing, I would like to record my appreciation for the support
of our shareholders, our financiers and our customers and the
efforts and enterprise of our employees and contractors during
the year. I also want to acknowledge the support and guidance
provided by the board during a period of extraordinary and
demanding events.
FY20 has been marked by tragedy in the communities in which
we work and live, a mixture of achievement and disappointment
with our business expectations and the disruption, stress
and harm brought by the pandemic. We are mindful of, and
acknowledge, the impacts of these events during the year and
ongoing. We reaffirm our commitment to the well-being and
development of the communities in which we operate; to our
people and their families; and to rewarding the trust and patience
of our shareholders and financiers.
David Maxwell
Managing Director
14
Cooper Energy’s Legacy Foundation provided financial support
to the Royal Flying Doctor Service to deliver critical health services
following the Gippsland bushfires and in response to COVID.
15
Reserves and Resources
Reserves
Cooper Energy’s 2P Reserves at 30 June 2020 are assessed to be 49.9 million barrels of oil equivalent (MMboe) compared with the previous
corresponding result of 52.7 MMboe. Key factors contributing to the movement in 2P Reserves were production of 1.6 MMboe in FY20,
PEL 92 drilling results and future development programs, adjustments to gas plant fuel requirements and de-booking of remaining reserves
following Minerva field shut-in in September 2019.
Reserves at 30 June 2020
Category
Unit
1P (Proved)
2P (Proved and Probable)
3P (Proved, Probable and Possible)
Developed
Undeveloped
Total
Developed Undeveloped Total
Developed Undeveloped
Total
Sales Gas
PJ
Oil + Cond MMbbl
Total 1
MMboe
184
0.7
30.7
29
0.1
4.8
213
0.8
35.5
255
1.3
42.9
41
6.6
6.9
296
6.9
49.9
344
1.9
58.0
49
0.4
8.5
393
2.3
66.6
1 Reserves exclude Cooper Energy’s share of future fuel usage. Totals may not reflect arithmetic addition due to rounding. The Reserves information
displayed should be read in conjunction with the information in the Notes on calculation of Reserves and Contingent Resources provided in this
document.
Year-on-year movement in 2P Reserves (MMboe)
Proved and Probable 2P Reserves (MMboe, net)
Category
Cooper
Otway
Gippsland
Reserves at 30 June 20191
FY20 Production 2
Revisions/Aquisitions
Reserves at 30 June 20203
1.8
(0.2)
(0.0)
1.6
10.9
(1.0)
(0.4)
9.5
40.0
(0.4)
(0.8)
38.8
Total
52.7
(1.6)
(1.2)
49.9
1 As announced to the ASX on 12 August 2019.
2 Otway and Cooper Basin production from 1 July 2019 to 30 June 2020 (inclusive).
3 Totals may not reflect arithmetic addition due to rounding.
Reserves by basin and product at 30 June 2020
Category
Unit
1P (Proved)
2P (Proved and Probable)
3P (Proved, Probable and Possible)
Cooper Otway Gippsland Total 1 Cooper Otway Gippsland Total 1 Cooper Otway Gippsland Total 1
Reserves at 30 June 2020 Developed and Undeveloped (net to Cooper Energy)
Developed
Sales Gas
PJ
Oil + Cond
MMbbl
Developed total 1
MMboe
Undeveloped
Sales Gas
PJ
Oil + Cond
MMbbl
Undeveloped total 1 MMboe
Total 1, 2
MMboe
0.0
0.7
0.7
0.0
0.1
0.1
0.8
9.1
0.0
1.5
28.8
0.0
4.7
6.2
174.4
183.5
0.0
0.7
28.5
30.7
0.0
0.0
0.0
28.8
0.1
4.8
28.5
35.5
0.0
1.3
1.3
0.0
0.3
0.3
1.6
17.2
237.5
254.7
0.0
2.8
40.6
0.0
6.6
9.5
0.0
1.3
38.8
42.9
0.0
0.0
0.0
40.6
0.3
6.9
38.8
49.9
0.0
1.9
1.9
0.0
0.4
0.4
2.3
23.7
319.8
343.5
0.0
3.9
49.5
0.0
8.1
0.0
1.9
52.3
58.0
0.0
0.0
0.0
49.5
0.4
8.5
12.0
52.3
66.6
1 The conversion factor 1 PJ = 0.163 MMboe has been used to convert from Sales Gas (PJ) to oil equivalent (MMboe) for the Otway and Gippsland basins.
2 The method of aggregation is by arithmetic sum by category. As a result, the 1P estimates may be conservative and the 3P estimates may be optimistic
due to the effects of arithmetic summation.
16
Contingent Resources
Cooper Energy’s 2C Contingent Resources at 30 June 2020 have increased since 30 June 2019 by 8.0 MMboe to 34.9 MMboe. The key factor
contributing to the revision is the booking of Annie gas resource following exploration success at Annie-1 in September 2019.
Contingent Resources at 30 June 2020
Category
1C
2C
3C
Basin
Gippsland
Otway
Cooper
Total 1
Gas
PJ
Oil/Cond
MMbbl
Total
MMboe
84
32
0.0
116
2.2
0.03
0.4
2.6
15.9
5.3
0.4
21.6
Gas
PJ
135
52
0.0
187
Oil/Cond
MMbbl
Total
MMboe
3.4
0.1
0.8
4.4
25.5
8.5
0.8
34.9
Gas
PJ
212
64
0.0
276
Oil/Cond
MMbbl
Total
MMboe
5.4
0.1
1.4
6.9
40.1
10.5
1.4
52.0
1 Totals may not reflect arithmetic addition due to rounding. The Contingent Resources information displayed should be read in conjunction with the
information in the Notes on calculation of Reserves and Contingent Resources provided in this document.
Year-on-year movement in Contingent Resources (MMboe)
Category
Contingent Resources at 30 June 2019 1, 2
Revisions
Contingent Resources at 30 June 2020 1, 2
1 As announced to the ASX on 12 August 2019.
2 Totals may not reflect arithmetic addition due to rounding.
1C
18.0
3.7
21.6
2C
26.9
8.0
34.9
3C
41.5
10.5
52.0
Notes on calculation of reserves and resources
Reference points for Cooper Energy’s petroleum Reserves and
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 statement are as at 30 June 2020. All Reserves and
Contingent Resources figures in this document are net to Cooper
Energy unless otherwise stated. The Reserves exclude Cooper
Energy’s share of future fuel usage.
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
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 uncertainty relating to each of the key reservoir input parameters
to predict the likely range of outcomes.
Project and field totals are aggregated by arithmetic summation by
category. Aggregated 1P and 1C estimates may be conservative,
and aggregated 3P and 3C estimates may be optimistic due to the
effects of arithmetic summation.
provided by the permit Operators (Beach Energy Ltd for PEL 92 and
Totals may not exactly reflect arithmetic addition due to rounding.
Senex Ltd for Worrior Field).
The conversion factor of 1 PJ = 0.163 MMboe has been used to
convert from Sales Gas (PJ) to Oil Equivalent (MMboe).
17
Reserves and Resources
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-Netherby and Minerva). The Cooper
Basin totals comprise the arithmetically aggregated PEL 92 project
fields and the arithmetic summation of the Worrior project Reserves.
The Gippsland Basin total comprises Reserves in Sole 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 assessment used deterministic simulation modelling and
probabilistic resource estimation for the Waarre C Formation in the
Annie Field. This methodology incorporates a range of uncertainty
relating to each of the key reservoir input parameters to predict
the likely range of outcomes. This approach is consistent with the
definitions and guidelines in the Society of Petroleum Engineers
(SPE) 2007 Petroleum Resources Management System (PRMS).
Qualified Petroleum Reserves and Resources
Evaluator Statement
The information contained in this report regarding the Cooper
Energy 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, 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
The Contingent Resources assessment includes resources in the
5.41, and has consented to the inclusion of this information in the
Gippsland, Otway and Cooper Basins. In the Otway Basin, the
form and context in which it appears.
Contingent Resources assessment at Annie gas field in VIC/P44
reported on 24 February 2020 has been upgraded at 30 June 2020.
The change is a result of continued technical studies following
the Annie-1 discovery announcement to the ASX on 6 September
2019. The update has resulted in an immaterial increase to Annie
2C gas Contingent Resources from 54.5 PJ to 57.4 PJ (100% gross
working interest).
Movement in Reserves 12 months to 30 June 2020
Reserves1
Production
FY19
Revisions/Aquisitions
Reserves 2, 3
FY20
1 As announced to the ASX on 12 August 2019.
Proved (1P)
MMboe
38.1
(1.6)
(0.9)
35.5
Proved and Probable (2P)
Proved, Probable and Possible (3P)
MMboe
MMboe
52.7
(1.6)
(1.2)
49.9
73.3
(1.6)
(5.1)
66.6
2 The conversion factor 1 PJ = 0.163 MMboe has been used to convert from Sales Gas (PJ) to oil equivalent (MMboe) for the Otway and Gippsland basins.
3 The method of aggregation is by arithmetic sum by category. As a result, the 1P estimates may be conservative and the 3P estimates may be optimistic
due to the effects of arithmetic summation.
18
Far Saracen support vessell on location in Otway Basin.
19
Operations
Production
Cooper Energy’s oil and gas
production for the year totaled
1.56 MMboe compared with
1.31 MMboe in the previous
year. The increase is due to the
commencement of gas
production from the Sole gas
field in the Gippsland Basin.
Safety
A detailed report, and
discussion of the company’s
safety management and
performance is provided in
the 2020 Sustainability Report.
The report, which has been
released contemporaneously
with the annual report can
be viewed and downloaded
from the company’s website
www.cooperenergy.com.au.
20
Production: 12 months to 30 June 1
2020
2019
Gas
PJ
Crude oil and
condensate
‘000 bbl
Total
million
boe
Gas
PJ
Crude oil and
condensate
‘000 bbl
Total
million
boe
Gippsland Basin
Otway Basin
Cooper Basin
2.1
6.2
-
3.5
193
0.34
1.02
0.19
-
6.6
-
-
4.7
238
-
1.07
0.24
1 All numbers rounded. Accordingly addition of individual numbers displayed may differ
insignificantly from the totals quoted.
Production by region MMboe
1.22
1.07
0.34
1.02
0.27
0.24
0.19
0.68
0.25
0.25
2017
2018
2019
2020
0.32
0.44
2016
Otway Basin
Gippsland Basin
Cooper Basin
South Sumatra, Indonesia
Safety metrics year ended 30 June
2020
2019
Hours worked
Recordable incidents
Lost time injuries
Lost time injury frequency rate
Total recordable injury frequency rate (TRIFR)1
Industry TRIFR2
283,672
505,300
1
1
3.53
3.53
5.27
0
0
0.0
0.0
3.48
1 TRIFR – Total Recordable Injury Frequency Rate all recordable incident data (Medical Treatment Injuries
+ Restricted Work/Transfer Case + Lost Time Injuries + fatalities) multiplied by 1,000,000 then divided by
total hours worked.
2 Industry TRIFR is NOPSEMA benchmark for offshore Australian operations.
Cuttings sample from 2,018 metres deep
on the Annie-1 well, drilled in Q3 2019.
21
Operations
Offshore Otway Basin
The company’s interests in the offshore
Production
Otway Basin include:
Year ended 30 June
2020
2019
• a 50% interest in, and Operatorship of,
the producing Casino Henry Netherby
(“Casino Henry”) Joint Venture (VIC/L24
Casino Henry
• Gas PJ
5.89
and VIC/L30). Mitsui E&P Australia and
• Condensate kbbl
2.76
its associated entities (“Mitsui”) hold the
remaining 50% interest;
Minerva
• Gas PJ
• a 50% interest in, and Operatorship, of
production licences VIC/L33 and VIC/L34
• Condensate kbbl
which contain part of the Black Watch
Total MMboe
0.32
0.76
1.02
5.52
1.7
1.0
3.0
1.07
gas field. Mitsui holds the remaining
50% interest;
• a 50% interest in, and Operatorship of,
the VIC/P44 exploration permit. Mitsui
holds the remaining 50% interest;
• a 100% interest in the exploration permit
VIC/P76;
As at 30 June
Developed
• Gas PJ
Undeveloped
• a 50% interest in, and Operatorship
• Gas PJ
of, the Athena Gas Plant (previously
known as the Minerva Gas Plant) located
Total Gas PJ
17
41
58
24
43
67
onshore Victoria. Mitsui holds the
remaining 50% interest; and
Contingent Resource (2C)
• a 10% interest in the Minerva gas field
As at 30 June
2020
2019
(VIC/L22) which ceased production
• Gas PJ
52
18
on 3 September. BHP Petroleum is the
Operator and holder of a 90% interest.
Casino Henry
The Casino Henry gas operations produce
gas and condensate from the Casino field in
VIC/L24, and the Henry and Netherby fields
in VIC/L30. The fields are located 17 km
to 25 km offshore Victoria in water depth
ranging from 65 m to 71 m.
Netherby-1), with production from a
maximum of 3 wells at any one time.
Gas produced from Casino Henry is
transported by a 12-inch subsea pipeline
to the processing facility at Iona owned
by Lochard Energy. Casino was brought
online in January 2006 and the Henry and
Netherby fields in February 2010. Cooper
Energy’s share of gas from Casino Henry
is currently sold to AGL Energy under
a 12-month contract to 31 December
2020. The company’s gas production for
the subsequent calendar year is partly
2022 calendar years.
Minerva
The Minerva gas field is located in
production licence VIC/L22 located 9
km offshore Victoria in a water depth of
approximately 60 metres. The field reached
end-of-life during the year and was shut-in
in September 2019. The company’s share of
production from Minerva for the year was
0.32 PJ and 0.76 kbbl barrels of condensate
compared to the previous year’s contribution
of 1 PJ of gas and 3.0 kbbl of condensate.
Athena Gas Plant Project
The Athena Gas Plant is located
approximately 5 km north-west of Port
Campbell and is connected directly to the
SEAGas Port Campbell to Adelaide Pipeline
and to the South West Pipeline, owned by
APA Group. The plant was commissioned in
Proved and Probable Reserves
contracted. Cooper Energy have contracted
2020
2019
supply of 1 PJ from Casino Henry to
Visy Glass International in both 2021 and
The licences are covered entirely by
January 2005 as the Minerva Gas Plant and
high-quality 3D seismic surveys acquired
entered care and maintenance following
between 2001 and 2007. The hydrocarbon
the cessation of production at Minerva.
reservoirs discovered and produced to date
are in the Cretaceous Waarre Formation.
The depth of the top Waarre Formation
at the discovered fields range between
approximately 1,500 metres to 2,000 metres.
As foreshadowed in the 2019 Annual
Report, Cooper Energy and Mitsui acquired
the plant in December 2019 for the purpose
of processing gas from Casino Henry
and gas discoveries made in the region.
Casino Henry consists of a subsea
The Athena Gas Plant has gas processing
development comprising four producing
capacity of approximately 150 TJ/day and
wells (Casino-4, Casino-5, Henry-2 and
hydrocarbon liquids processing facilities.
22
Adelaide
Warrnambool
PEP 168 (50%)
Cooper Energy
tenement
Gas field
Gas pipeline
VICTORIA
Melbourne
Processing Casino Henry gas through
Minerva is expected to deliver processing
cost and productivity benefits.
Final Investment Decision on the project
to connect the plant was taken after year-
end. The plant is expected to be ready to
receive first gas from Casino Henry in the
September quarter 2021, although the
potential for delays arising from COVID-19
is noted.
Otway Phase 3 Development
Project
The Otway Phase 3 Development Project
VIC/L34 (50%)
VIC/L33 (50%)
Speculant
Halladale
Black Watch
VIC/P44 (50%)
Martha
Iona Gas Plant
Athena Gas Plant (50%)
VIC/P44 (50%)
Annie
VIC/L30 (50%)
Henry
Netherby
Minerva
VIC/L22 (10%)
Casino
0
10
kilometres
VIC/P44 (50%)
VIC/P76 (100%)
VIC/L24 (50%)
(OP3D) involves development of the Annie
Otway 160AR
gas field and infill drilling of the Henry gas
field to enable production of more than
100 PJ of gas (gross joint venture volume,
Cooper Energy share 50%) via the Athena
Gas Plant. OP3D is currently in the Concept
Select phase. The project is scheduled
to complete this phase in the first half
of FY21.
Development drilling required for OP3D
could be incorporated into the broader
drilling rig program planned to commence
in the second half of calendar 2022,
enabling first gas from late in FY23.
Black Watch
(VIC/L33 and VIC/L34)
an extended reach onshore well. Cooper
at Annie-1. Drilling of Elanora-1 will be
Energy is pursuing commercial agreement
considered for a drilling campaign being
which recognises its equity share of Black
planned to commence in FY23, subject to
Watch gas reserves.
Exploration
Annie gas discovery
A two-well gas exploration program in
the offshore Otway Basin was launched in
August 2019.
rig availability.
VIC/P76
VIC/P76 was awarded to Cooper Energy
100% in September 2019. The granting
of VIC/P76 consolidated Cooper Energy’s
offshore Otway acreage position around
existing infrastructure and added to the
The first well, Annie-1 in VIC/P44, made
exploration prospect inventory. The permit
a new gas field discovery, identifying a
adjoins the Annie gas discovery and
gross 70 metre gas column in the primary
Casino production licence and is traversed
target Waarre C formation with net gas
by the Casino gas pipeline, which is to be
pay thickness of 62 metres. A Contingent
connected to the Athena Gas Plant.
Cooper Energy has a 50% interest in
Resource assessment was issued on 24
production licences VIC/L33 and VIC/L34
February. Annie is assessed to hold gross
which were granted during the year to
2C Contingent Resources of 57 PJ1, with
the company and its joint venture partner
Cooper Energy’s equity share being 50%.
Mitsui. The licences comprise the same
Development of the field is being assessed
area as the Retention Leases VIC/RL11
under the Otway Phase 3 Development
and VIC/RL12 previously held by Cooper
Project discussed under Offshore Otway
Energy and Mitsui and contain part of the
development, following.
There are no previous wells drilled within
the permit area. Good quality 3D seismic
data covers most of the permit, from
which Cooper Energy has identified several
amplitude-supported prospects. The most
significant, Nestor, has many similarities
to the Annie gas discovery including the
Waarre C reservoir, trap configuration
Black Watch gas field which extends into
adjoining production licences held by
Beach Energy Limited (“Beach”).
Drilling of the second well in the program,
and potential resource size. Subsurface
Elanora-1 in VIC/L24, was deferred
analysis of this prospect, and others, has
following repeated loss of tension on
commenced with a view to identifying
Beach commenced production from its
the mooring lines attached to the Ocean
the preferred candidate for drilling in the
portion of the field during the year from
Monarch drilling rig whilst on location
campaign being planned for FY23.
1 Contingent Resource for the Annie gas resource was announced to ASX on 24 February and updated on 31 August 2020. Cooper Energy confirms
that it is not aware of any new information or data that materially affects the information included in these announcements and that all the material
assumptions and technical parameters underpinning the estimates in the announcements continue to apply and have not materially changed.
23
Operations
Gippsland Basin
Production
Year ended 30 June
• Gas PJ
Sole
2020
2.10
2019
-
The Sole gas field is located 36 km offshore
Victoria in water depths of approximately
Proved and Probable Reserves
At 30 June
• Gas PJ
2020
238
2019
245
Contingent Resources
125 m. The field is connected to APA
Group’s (“APA”) Orbost Gas Processing
Plant by a 65 km pipeline and umbilical
control system. The plant, formerly
known as the Patricia Baleen Gas Plant,
is connected to the Eastern Gas Pipeline.
Sole is an entirely subsea production
system comprising wells, Sole-3 and
Sole-4, with subsea wellheads, manifold
2020
2019
and tieback and control via the Orbost
At 30 June
• Gas PJ
• Oil/Condensate
MMbbl
135
3.4
121
3.4
Cooper Energy’s interests in the Gippsland
Basin comprise:
• a 100% interest, and Operatorship of,
VIC/L32 which contains the Sole gas field;
• a 100% interest and Operatorship of
VIC/RL13, VIC/RL14 and VIC/RL15,
which contains the Manta gas and liquids
resource;
• a 100% interest, and Operatorship of,
VIC/RL16, which contains the shut-in and
largely depleted Patricia-Baleen gas field;
• a 100% interest in the Patricia Baleen to
Orbost gas pipeline; and
• a 100% interest in, and Operatorship, of
the exploration permits VIC/P72 and VIC/
P75 located in the Gippsland Basin.
plant. Development of the field was
completed in July 2019.
Gas production from Sole commenced
later, and was lower, than anticipated due to
delays in construction and commissioning
of the Orbost Gas Processing Plant.
Construction work to upgrade the plant to
process gas from Sole was completed in
January 2020. Commissioning of the plant
is yet to be completed. Sole supplied 2.1 PJ
of gas for commissioning purposes to 30
June, all of which was sold to gas customers
on a spot basis.
under a Transition Agreement signed
after year end to establish a firm supply
capability at the Orbost Gas Processing
Plant and to progress initiatives to improve
plant performance to the levels required
for practical completion of the plant.
Sole’s gas reserves are largely committed
under long term take-or-pay contracts
Resources 1 of 121 PJ of gas and 3.4 MMboe
of condensate. There is prospective
resource potential below the Manta gas
field in the Manta Deep prospect.
Manta is being considered as a follow-on
development to Sole, its proximity to which
enhances prospects for development.
Analysis has identified significant synergies
and cost savings if Manta is developed
and operated in coordination with Sole in
areas including control umbilicals, plant,
redundancies and maintenance. Provision
for Manta gas to access the Orbost plant
for processing has been incorporated
in the agreements executed by APA and
Cooper Energy.
An appraisal well is required prior to
a development decision on the field’s
Contingent Resources, which would
also present the opportunity to test the
Prospective Resource assessed in deeper
reservoirs. Planning for this well, Manta-3,
has progressed and the well may be
drilled as part of the campaign targeted
to commence in the first half of FY23
subject to rig availability.
Patricia Baleen is a largely-produced
offshore gas field located in production
licence VIC/RL16 which is under care and
maintenance after being shut-in in 2008.
The field is connected to the Orbost Gas
Processing Plant by a 24 km pipeline, also
owned by Cooper Energy. Contingent
Resources (2C) of approximately 14 PJ are
assessed for the Patricia Baleen field at
Proved and Probable Reserves of
with industrial and utlility customers
238 PJ at 30 June compare to 245 PJ at
in Australia. Commencement of these
the beginning of the year. Factors in
contracts has been deferred pending
30 June 2020.
the movement of Proved and Probable
establishment of a firm supply capability
Reserves for the period were production
from the plant.
and a revision arising from the application
of measured plant fuel usage by the
Manta
Orbost Gas Processing Plant and Sole gas
The Manta gas field is located in retention
heating value under production conditions.
licences VIC/RL13, VIC/RL14 and
VIC/RL15, 35 km from Sole and 58 km
from the Orbost Gas Processing Plant. The
field is assessed to contain 2C Contingent
1 Contingent Resource for the Manta gas and liquids
resource was announced to ASX on 12 August 2019.
Prospective Resource for the field was announced
to the ASX on 4 May 2016. Cooper Energy confirms
that it is not aware of any new information or data
that materially affects the information included
in the announcements of 12 August 2019 or
4 May 2016 and that all the material assumptions
and technical parameters underpinning the estimates
in the announcements continue to apply and have
not materially changed.
24
APA and Cooper Energy are cooperating
Patricia Baleen
VICTORIA
Orbost
Sydney
LIN E
E
E A S T E RN GAS P IP
Orbost Gas Processing Plant (APA)
Melbourne
Lakes Entrance
VIC/RL16 (100%)
VIC/P72 (100%)
VIC/L32 (100%)
Patricia-Baleen
Longtom
Tuna
Snapper
Kipper
Barracouta
Marlin
VIC/P75 (100%)
Flounder
Fortescue
Sole
Sole
Manta
Chimaera
Chimaera
Manta
Basker
Gummy
VIC/RL15 (100%)
VIC/RL14 (100%)
Mackerel
VIC/RL13 (100%)
Blackback
Bream
Kingfish
Cooper Energy tenement
Gas field
Oil field
Gas pipeline
Oil pipeline
ppsland 122AR
Gippsland_122AR
0
20
kilometres
Plan area
TA
VIC/P72
It is anticipated an exploration well could
Previous exploration within the area
be drilled as part of the campaign being
has been impacted by significant depth
planned for FY23, subject to rig availability.
conversion issues related to velocity
VIC/P75
complexities above reservoir targets.
However, recent advances in 3D seismic
VIC/P75 was awarded to Cooper Energy
reprocessing have provided greater clarity
on a 100% equity basis in September
for the mapping of subsurface structures.
2019. This exploration permit is located
Interpretation has begun of licensed
in the central area of the Gippsland
3D seismic data covering the permit that
Basin surrounded by major oil and gas
was reprocessed in 2018.
VIC/P72 lies in proximity to several
Esso-operated gas and oil fields including
Snapper, Marlin, Sunfish and Sweetlips
and the Longtom gas field operated by
SGH Energy. Prospect analogues to the
offset fields are identified in VIC/P72.
The first three years’ guaranteed work
program consists of 260 km2 of 3D seismic
reprocessing and studies and the drilling
of one exploration well.
Interpretation of reprocessed 3D seismic
and quantitative interpretation volumes
fields including the Marlin, Snapper and
Barracouta gas fields to the north and
the Kingfish and Fortescue oil fields in
the south and east respectively. Three-
has been completed. Geological analysis
dimensional seismic data is available
to identify and rank select preferred
candidates for drilling was conducted.
covering most of the permit area.
VIC/P75 was granted to Cooper Energy
for a six-year term, the first three years of
which entails a guaranteed work program
consisting of seismic reprocessing and
geological/geophysical studies.
25
Review of Operations
Onshore
Cooper Basin
Cooper Energy holds interests in 35
• a 30% interest in PPL 207 which holds
Proved and Probable Reserves
petroleum retention licences and eleven
the producing Worrior oil field;
production licences in the South Australian
Cooper Basin. The company’s activities are
primarily focused on tenements held by
the PEL 92 Joint Venture (‘PEL 92‘) on the
• a 30% interest in PRL’s 231-233 and 237
• a 19.17% interest in the PRL’s 207-209,
and
western flank of the basin, which provided
• a 20% interest in the PRL’s 183-190
approximately 12% of Cooper Energy’s
(ex PEL-110).
million barrels
as at 30 June
Developed
• Crude oil
Undeveloped
• Crude oil
total production and 94% of its liquids
production for 2020.
During the year the company participated
Total
in a total of 16 wells drilled by the PEL 92
• Crude oil
Joint venture and tenement interests
Joint Venture. The program included
comprise:
• a 25% interest in the PEL 92 Joint Venture
which holds PRL’s 85 to 104, including the
producing Butlers, Callawonga, Christies,
Elliston, Germain, Parsons, Perlubie,
Rincon, Rincon North, Sellicks, Silver
Sands and Windmill oil fields;
13 appraisal wells, 1 development well
and 2 exploration wells. Three appraisal
wells were cased and suspended as future
oil producers with all other wells being
plugged and abandoned.
Production
million barrels
as at 30 June
2020
2019
1.3
0.3
1.6
1.5
0.3
1.8
2020
2019
• Crude oil
0.19
0.24
Onshore Otway Basin
Cooper Energy holds interests in five
gas exploration after that date. All onshore
production test yielded variable results,
exploration licences and one retention
Victorian permits remain in suspension
recording measured gas flow exceeding
licence in the onshore Otway Basin:
until that time.
Exploration
• 30% interests in PEL 494, PRL 32, and
PELA 680, South Australia. Beach Energy
is the Operator and holds the remaining
interest in these licences;
• 50% interests in Bridgeport Energy-
operated PEP 150 and Beach Energy-
operated PEP 168 in Victoria; and
The company’s primary focus in the
suggests potential for a larger gas pool
onshore Otway Basin is exploration of gas
than interpreted via pressures. It is
plays associated with the Sawpit and Pretty
considered possible Dombey-1 drilled a
Hill formations, primarily within the Penola
smaller compartment connected to a
Trough. The potential of this play was
broader accumulation.
proven by the gas field discovery made by
18 MM scfg/day before a subsequent decline
in flow test pressure. Re-pressurisation
of the reservoir after an extended shut-in
• a 75% interest in PEP 171 in Victoria
the Haselgrove-3 sidetrack well drilled by
which may reduce by up to a further 25%
Beach Energy in PPL 62 in 2017, a licence
on fulfilment of farm-in arrangements
surrounded by PEL 494. This region is
executed with Vintage Energy.
considered favourable for gas exploration
Activity in the Victorian permits was
suspended pursuant to the moratorium
imposed by the state government on
and development due to its prospectivity,
existing infrastructure and local industrial
and residential gas demand.
Dombey-1 has derisked several other
prospects within PEL 494 and upgraded the
prospectivity of the north-western flank of
the Penola Trough. The well also highlighted
the need for better quality subsurface
definition than afforded by the 2D seismic
dataset currently available. Planning is
underway for a 3D seismic acquisition
onshore petroleum exploration and
The PEL 494 joint venture drilled one well
program at Dombey, which is most likely to
production until 30 June 2020. The passage
during the period, Dombey-1, which
be conducted later in 2021.
of the Petroleum Legislation Amendment
resulted in a new gas discovery. The well
Act 2020 during the year extended the
encountered a gross gas column of 44.5 m,
moratorium until 30 June 2021 and
with net pay thickness of 25 m in the
provided for resumption of conventional
Pretty Hill Formation. A subsequent
Dombey-1 was part funded by a
$6.89 million PACE Gas Round 2 grant by
the South Australian Government.
26
Cooper Basin
Kingston SE
SOUTH AUSTRALIA
Naracoorte
PEL 494 (30%)
PRL 32 (30%)
e
Robe
Beachport
Dombey
Penola
Katnook
Nangwarry
PELA 680 (30%)
Millicent
Cooper Energy
tenement
Gas field
Gas pipeline
VICVICTORTORIAIA
VICTORIA
PEP 171 (75%)
Hamilton
Mount Gambier
PEP 150 (50%)
Portland
Plan area
0
20
40
TAS
kilometres
Otway 161AR
Otway 161AR
Onshore Otway Basin
27
Portfolio
Cooper Energy Exploration and Production Tenements
Region: Australia
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 South)
PPL 248
(Rincon/Rincon North)
PPL 249 (Elliston)
PPL 250 (Windmill)
PRLs 85-104
PRLs 231-233
PRL 237
PRLs 207-209
PRLs 183-190
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
4.3
6.4
5.5
1.8
2.1
0.1
1.5
2.0
0.8
0.6
Beach Energy
Production
Senex Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Onshore
1889.3
Beach Energy
Exploration
Onshore
Onshore
Onshore
277.2
Senex Energy
Exploration
17.7
Senex Energy
Exploration
296.5
727.5
Senex Energy
Exploration
Senex Energy
Exploration
20%
Onshore
Otway Basin
State
Tenement
Interest
Location
Area (km2)
Operator
Activities
South Australia
PEL 494
Victoria
PELA 680
PRL 32
VIC/L22
VIC/L24
VIC/L30
VIC/L33
VIC/L34
VIC/P44
VIC/P76
PEP 150
PEP 168
PEP 171
Athena Gas Plant
Onshore
Beach Energy
Exploration
Onshore
1923.0
Beach Energy
Exploration
Onshore
Offshore
Offshore
Offshore
Offshore
Offshore
Offshore
36.9
58.0
199.0
200.0
127.0
Beach Energy
Exploration
BHP
Production ceased
Cooper Energy
Production
Cooper Energy
Production
Cooper Energy
Development
6.0
Cooper Energy
Development
599.0
161.0
Cooper Energy
Exploration
Cooper Energy
Exploration
100%
Offshore
50%
50%
75% 1
50%
Onshore
3,212.0
Bridgeport
Exploration
Onshore
795.0
Beach Energy
Exploration
Onshore
1,974.0
Vintage Energy
Exploration
Onshore
n/a
Cooper Energy
Gas Processing
1 Subject to farm-in agreement which will reduce Cooper Energy’s interest by up to a further 25%.
28
25%
30%
25%
25%
25%
25%
25%
25%
25%
25%
25%
30%
24%
19.17%
30%
30%
30%
10%
50%
50%
50%
50%
50%
Zacc Paparella, Geologist and Phil Clegg, Technical
Assistant on board Ocean Monarch at Annie-1.
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
134.0
Cooper Energy
Retention
Offshore
Offshore
Offshore
Offshore
Offshore
Offshore
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
29
Board of Directors
Board members have been photographed remotely, consistent with virtual board meetings
having been held from late February 2020 due to Coronavirus restrictions.
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 Bednall
LLB (Hons)
Appointed 31 March 2020
subject to confirmation by shareholders
at the Company’s 2020 AGM
Independent
Non-Executive Director
Victoria (Vicky) Binns
B. Eng (Mining – Hons 1), Grad Dip SIA,
FAusIMM, GAICD
Appointed 2 March 2020
subject to confirmation by shareholders
at the Company’s 2020 AGM
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
President of the Commonwealth
Remuneration Tribunal (since
2003) and Chairman of Dexus
Wholesale Property Limited (since
September 2020). He is Deputy
Chairman of Whitehaven Coal
Limited ASX: WHC (since 2007).
Mr Conde is a former Chairman of
Bupa Australia (2008-2018).
Special responsibilities
Mr Conde is Chairman of the
Board of Directors. He is also a
member of the People and
Remuneration Committee and is
the Chairman of the 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 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.
Current and other directorships
in the last 3 years
Mr Maxwell is a Director of 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 (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).
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).
Special responsibilities
Mr Bednall is a member of the
People & Remuneration
Committee, the Nomination
Committee and the Risk
& Sustainability Committee.
Experience and expertise
Ms Binns has over 35 years’
experience in the global resources
and financial services sectors
including more than 10 years in
executive leadership roles at BHP
and 15 years in financial services
with Merrill Lynch Australia and
Macquarie Equities. During her
career at BHP, Ms Binns’ roles
included Vice President Minerals
Marketing, leadership positions
in the metals and coal marketing
business, Vice President of Market
Analysis and Economics and was
a member of the first BHP Global
Inclusion and Diversity Council.
Prior to joining BHP, Ms Binns held
a number of board and senior
management roles at Merrill Lynch
Australia including Managing
Director and Head of Australian
Research, Head of Global Mining,
Metals and Steel, and Head of
Australian Mining Research. She
was also co-founder and Chair of
Women in Mining and Resources
Singapore.
Current and other directorships
in the last 3 years
Ms Binns is currently a Non-
Executive Director of ASX-listed
company Evolution Mining
(since 2020).
Special responsibilities
Ms Binns is a member of the
Audit Committee, the People &
Remuneration Committee and the
Risk and Sustainability Committee.
30
Independent
Non-Executive Director
Ms Elizabeth A. Donaghey
B.Sc., M.Sc.
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
Independent
Non-Executive Director
Ms Alice J. M. Williams
B.Com FAICD, FCPA, CFA
Appointed 12 October 2011
Appointed 28 August 2013
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
Mr Schneider is Chairman of the
People and Remuneration
Committee, and a member of
the Nomination Committee and
the Audit Committee.
Experience and expertise
Ms Donaghey brings over 30 years’
experience in the energy sector
including technical, commercial and
executive roles in EnergyAustralia,
Woodside Energy and BHP
Petroleum.
Ms Donaghey’s experience includes
Non-Executive Director roles at
Imdex Ltd (an ASX-listed provider
of drilling fluids and downhole
instrumentation), St Barbara Ltd
(a gold explorer and producer),
and the Australian Renewable
Energy Agency. She has performed
extensive committee roles in these
appointments, serving on audit
and compliance, risk and audit,
technical and regulatory,
remuneration and health and
safety committees.
Current and other directorships
in the last 3 years
Ms Donaghey is a Non-Executive
Director of the Australian
Energy Market Operator (AEMO)
(since 2017).
Special responsibilities
Ms Donaghey is a member of the
Risk and Sustainability Committee,
the People and Remuneration
Committee and the 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 Gordon is the Chairman of the
Risk and Sustainability Committee
and a member of the Audit
Committee.
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 Equity Trustees Ltd ASX:
EQT (since 2007), Djerriwarrh
Investments Ltd, Defence Health
(since 2010) and not for profit
Tobacco Free Portfolios (since
2018). Ms Williams has recently
stepped down as a Member of the
Foreign Investment Review Board.
Ms Williams was a Non-Executive
Director of the Victorian Funds
Management Corporation for the
period 2008 to 2018.
Special responsibilities
Ms Williams is the Chairman of the
Audit Committee and a member
of the Risk and Sustainability
Committee.
31
Executive Leadership Team
Executive Leadership Team members have been photographed remotely consistent with
revised work arrangements whilst Coronavirus restrictions were in place.
General Manager,
Commercial and
Business Development
Eddy Glavas
B.Acc CPA, MBA
Mr Glavas joined Cooper Energy
in August 2014 and has more than
20 years’ 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.
General Manager,
Projects and Operations
Michael Jacobsen
B. Eng (Hons)
Company Secretary
and General Counsel
Amelia Jalleh
BA, LLB (Hons), LLM
Mr Jacobsen has 28 years
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.
Ms Jalleh joined Cooper Energy
in August 2019 with more
than 18 years’ experience in
the international oil and gas
industry, including senior
corporate, commercial and legal
roles in Australia, the Middle East,
North America and South-East
Asia for Talisman Energy, King &
Spalding LLP and Santos. Prior to
joining Cooper Energy, Ms Jalleh
was Director, Business Development
Asia-Pacific for Repsol, based
in Singapore.
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).
Managing Director
David Maxwell
M. Tech FAICD
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 out-
standing long term achievement in
the Australian oil and gas industry.
32
General Manager, HSEC
and Technical Services
Iain MacDougall
BSc (Hons)
Chief Financial Officer
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.
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.
General Manager,
Exploration
and Subsurface
Andrew Thomas
BSc (Hons)
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 29 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.
33
Key Performance Indicators
Operational
Production
12 months
to 30 June
MMboe
Proved and Probable reserves
MMboe
Wells drilled
number
Exploration wells spudded
number
2012
2013
2014
2015
2016
2017
2018
2019
2020
0.52
1.88
10
6
0.49
2.16
13
8
0.59
2.01
11
5
0.48
3.08
9
4
0.46
3.00
1
-
0.96
11.7
9
1
1.49
52.4
4
2
1.31
52.7
0
0
1.56
49.9
18
4
Reserve replacement ratio1
percent
(113)%
98%
71%
333%
18%
768% 2,380%
(206)%
(56)%
Financial
Sales revenue
Other income
EBITDA
Profit before tax
Profit after tax / (loss)
Cash and term deposits
Other financial assets
Working capital
Accumulated profit
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
Cumulative franking credits
$ million
59.6
4.7
9.1
21.0
8.4
61.5
13.2
53.4
22.5
37.0
53.4
2.3
22.3
18.3
1.3
47.9
20.2
51.7
23.8
39.0
72.3
2.8
36.9
31.2
22.0
49.1
26.0
41.2
45.7
39.1
1.9
27.4
0.9
(58.4)
(37.4)
39.1
1.6
1.9
(18.8)
(26.0)
(7.0)
(63.5)
(34.8)
(12.3)
67.5
4.9
49.9
31.0
27.0
75.5
4.2
7.5
78.1
19.8
(75.2)
(13.2)
(110.0)
(12.1)
(86.0)
39.4
1.9
43.0
49.8
147.5
236.9
164.3
131.6
1.0
44.2
0.7
42.6
21.7
0.6
84.0
154.0
131.8
90.4
(17.7)
(52.6)
(64.9)
(37.9)
(49.9)
(136.0)
38.7
43.7
42.9
91.6
42.9
42.9
42.9
42.9
285.0
443.9
433.7
351.1
Total equity
$ million
136.9
137.2
167.8
103.9
Earnings per share
cents
2.8
0.4
6.4
(19.2)
(10.1)
(1.8)
1.8
(0.7)
(5.30)
Return on shareholders funds
percent
6.7%
0.9%
14.4% (46.7)% (38.0)%
(6.5)%
7.4%
(2.6)% (21.9)%
Total shareholder return
percent
25.0% (16.7)%
34.7% (51.5)% (12.2)%
72.7%
6.0%
40.3% (30.6)%
Average oil price
A$/bbl
114.63
112.31
124.08
85.48
60.75
61.89
99.61
106.19
83.75
Capital as at 30 June
Share price
Issued shares
$ per share
0.45
0.375
0.505
0.245
0.215
0.38
0.385
0.54
0.375
million
327.3
329.1
329.2
331.9
435.2
1,140.2
1,601.1
1,621.6
1,621.6
Market capitalisation
$ million
147.3
123.4
166.3
81.4
93.6
433.3
616.4
875.5
608.1
Shareholders
number
5,485
5,284
5,122
5,103
4,931
6,292
6,622
6,758
8,094
1 Reserve replacement ratio calculated by net 1P reserve addition/production.
34
Cooper Energy Limited and its controlled entities
Financial Report
For the year ended 30 June 2020
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
Capital Employed
10. Property, plant and equipment
11. Intangible assets
12. Exploration and evaluation assets
13. Oil and gas assets
14. Impairment
15. Provisions
16. Leases
17. Government grants
Funding and Risk Management
18. Interest bearing loans and borrowings
19. Net finance costs
20. Contributed equity and reserves
21. Financial risk management
22. Hedge accounting
Group Structure
23. Interests in joint arrangements
24. Investments in controlled entities
25. Parent entity information
Other Information
26. Commitments for expenditure
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
36
48
51
74
75
76
77
78
82
83
85
89
90
91
91
91
91
92
92
93
93
94
98
100
101
102
103
103
105
109
110
111
112
113
113
115
116
116
117
118
126
127
Abbreviations and Terms
Corporate Directory Inside back over
128
3535
Operating and Financial Review
For the year ended 30 June 2020
Operations
Cooper Energy Limited (“Cooper Energy” or the “Company”) generates revenue from the supply of gas to south-east Australia and oil production
in the Cooper Basin. The Group’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, Netherby (“Casino Henry”) gas fields;
• non-operated onshore oil production and exploration from the western flank of the Cooper Basin;
• the Athena Gas Plant (previously known as the Minerva Gas Plant) in the onshore Otway Basin;
• the Manta gas and liquids field in the offshore Gippsland Basin;
• the Annie gas discovery in the offshore Otway Basin;
• exploration in the offshore and onshore Otway Basin; and
• exploration in the offshore Gippsland Basin.
The Company is the Operator of all of its offshore gas production, exploration and development activities and of the Athena Gas Plant.
Reserves and Contingent Resources
Proved and Probable Reserves (2P) as at 30 June 2020 are estimated at 49.9 million boe (barrels of oil equivalent) compared with 52.7 million boe
at 30 June 2019. Contingent Resources (2C) as at 30 June 2020 are estimated at 34.9 million boe compared with 26.9 million boe at 30 June 2019.
Details of reserves and resources and the movement from the previous year are available in the ASX announcement ‘Reserves and Contingent
Resources Update’ of 31 August 2020.
As at 30 June 20201
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
237.5
57.8
0.0
295.3
0.0
0.0
1.6
1.6
38.8
9.4
1.6
49.9
134.8
49.4
0.0
184.2
3.4
0.1
0.8
4.4
25.5
8.5
0.8
34.9
1 As announced to the ASX on 31 August 2020. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by
arithmetic sum by category.
Workforce
At 30 June 2020 the Company had 75.9 full time equivalent (FTE) employees and 31.5 FTE contractors compared with 53.5 full time equivalent
(FTE) employees and 43.8 FTE contractors at 30 June 2019. The increase in employee numbers is attributable to resourcing the growth of the
Group’s operations, including the acquisition of the Athena Gas Plant, and the shift of a number of contract staff to full time employment.
Contractor numbers have fluctuated in line with the progress of both the Athena Gas Plant and the Sole Gas Project and requirements for the
2019 drilling program.
Health Safety Environment and Community
A single lost time injury occurred within the Company’s operations during the year. An employee of Diamond Offshore was injured on the
Ocean Monarch drill rig in September while it was on location in VIC/P44, albeit not under the direction of the Company. The Company has been
advised the injured worker has recovered and returned to work. Total recordable incident frequency rate for the period was 3.5 compared with
zero for FY19.
There were no reportable environmental incidents.
Production
Total production for the year was 1.56 million boe, 18% higher than the prior year’s 1.31 million boe, with the increase attributable to the
Sole gas field.
Gas production for the year was 8.3 PJ compared with 6.6 PJ in 2019. Significant features of the year’s production performance were the
commencement of supply from Sole in March and the cessation of operations at the Minerva gas field in offshore Otway Basin in September.
Sole produced a total of 2.1 PJ from the beginning of commissioning in March to 30 June.
Liquids production for the year consisted of 196.2 kbbl compared with 242.5 kbbl in the previous year. Approximately 98% of the FY20 liquids
production was sourced from the Cooper Basin, where production rates reflected natural decline.
Commercial
The Company’s strategy for creating shareholder value involves the development and operation of a portfolio style gas business to supply a tight
south-east Australia domestic gas market.
36
Operating and Financial Review
For the year ended 30 June 2020
Operations continued
Fundamental to this strategy is the Company’s management of its gas production and sales contract portfolios. Cooper Energy seeks to produce
gas from the most competitive sources of supply and to maintain a portfolio of contracts with blue-chip utility and industrial gas customers that
support stable long-term production and optimisation of supply sourcing. Reliability of cash flow and earnings are prioritised through pricing,
load factors and take-or-pay agreements that encourage stable sales through market and seasonal cycles.
FY20 brought an unforeseen change in market cycle through the impact of the COVID-19 pandemic on energy demand and prices.
The accounting impact of this is evident in the adjustments made to recognise the impact of the lower prevailing prices, and revised price
expectations, for uncontracted gas and asset carrying values as at 30 June 2020.
It is important to recognise these accounting adjustments hold no significance for the competitive position of the company’s gas, and its outlook
which is discussed under the heading ‘Business strategies and prospects’ following.
Furthermore, the merit of the company’s ‘long’ contract position whereby the majority of its proved and probable gas reserves are contract under
agreed prices without energy price linkage.
New gas contracts announced during the year included agreements with industrial gas users Visy and O-I Australia. The Sole gas field’s term
contract capacity is now fully committed until 2025 (inclusive of extensions). Production from Casino Henry is fully contracted for the 2020
calendar year. Approximately 1 PJ of the Company’s share of production from Casino Henry in FY21 is contracted.
Regional review
Gippsland Basin
The majority of the Company’s reserves, resources and anticipated production are attributable to the Gippsland Basin, offshore Victoria, Australia.
Cooper Energy is the operator and 100% interest holder in all of its Gippsland Basin interests. These comprise:
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. The Retention Leases also hold legacy infrastructure
associated with the Basker Manta Gummy (“BMG”) oil project;
c) VIC/RL16 which contains the shut-in Patricia-Baleen gas field, and infrastructure offering connection to the Orbost Gas Processing Plant; and
d)
exploration permits VIC/P72 and VIC/P75.
Production
First supply of gas from Sole occurred in March 2020 for the purposes of commissioning the Orbost Gas Processing Plant (owned and operated
by APA Group “APA”). Commissioning of the plant continued for the remainder of the financial year, resulting in variable and intermittent
production from the field. Sole supplied 2.1 PJ of gas into the Eastern Gas Pipeline during this period, all of which was sold on a spot basis under
contract to utility gas customers.
Sole Gas Project
The Sole Gas Project involved development of the Sole gas field by Cooper Energy and upgrading of the Orbost Gas Processing Plant (OGPP) to
process Sole gas by APA.
The offshore project was completed within schedule, below budget and with zero lost time injuries and zero reportable environmental incidents
after performance of 561,362 work hours at onshore, marine and subsea workplaces. Total capital cost for the offshore project was $335 million
compared to the budget of $355 million.
Commissioning of the plant upgrade is yet to meet the performance standards for completion, which includes demonstrated capacity to supply
68 TJ/day of Sole gas into the Eastern Gas Pipeline. As reported to the ASX, foaming in the absorber section of the plant has impaired output
rates and been accompanied by fouling which required two shutdowns for maintenance prior to 30 June.
The shutdowns and optimisation of operations by APA have resulted in improved plant performance.
APA and Cooper Energy are working collaboratively to improve plant performance to that required for the completion of commissioning.
Subsequent to year-end the two companies announced a Transition Agreement which establishes the commercial framework for this
collaboration and progress towards the commencement of firm gas supply and the practical completion of the OGPP. Under the agreement
revenue operating and capital costs will be shared while the OGPP proceeds to practical completion.
Root cause analysis to identify the cause of the foaming, has been ongoing with involvement of the OGPP technology provider. APA has
conducted minor plant modifications to improve performance, with further modifications planned for completion in September 2020. Planning
is also underway for Phase 2 works to increase gas processing capacity, which will include the flexibility to reconfigure the two absorber vessels
from a sequential to a parallel arrangement.
The Phase 2 works (scope currently being finalised) are currently planned to commence in the December quarter (timing subject to supply
chain and COVID-19 restrictions) for the resumption of production in the latter half of that quarter. If approved, it is expected the works would
commence in the December quarter 2020 (timing subject to supply chain and COVID-19 restrictions) for the resumption of production in the
latter half of that quarter. The cost of the Phase 2 works has not been finalised, with current estimates being $15 million (Cooper Energy share
$7.5 million).
37
Operating and Financial Review
For the year ended 30 June 2020
Operations continued
Commencement of term gas supply contracts from Sole has been deferred until the earlier of January 2021 or when permitted by the
commencement of firm supply from the OGPP. Whilst OGPP has demonstrated capability to maintain stable supply of 40-45 TJ/day,
Cooper Energy and APA are working to establish firm supply capability from the plant in advance of practical completion.
Development of Manta gas and liquids resource
Development of the Manta gas and liquids field is being pursued as the next phase of the Gippsland gas development, utilising economies
available through coordination with the Sole gas field development. Manta is assessed to contain Contingent Resources1 (2C) of 121 PJ of sales
gas and 3.4 million barrels of condensate.
A business case undertaken in 2015 affirmed the commercial potential of the field. Appraisal of the field’s Contingent Resources is considered
necessary for confirmation of the assessed resource. An appraisal/exploration well, Manta-3, will also test the potential of a prospective resource
in deeper reservoirs and inform a development decision on the field and the final firm development plan. The drilling of Manta-3 is being
considered in the planning of the offshore drilling campaign expected to commence in FY23.
Abandonment and remediation of BMG
Planning for the abandonment of the BMG legacy oil infrastructure and lease remediation was advanced during the year with a view to FID and
contracting of a well intervention vessel in the second half of FY21. Provisions for the performance of the abandonment have been reviewed and
upgraded to reflect updates on costs and assessment of regulator expectations acquired during the year.
It is expected the abandonment and remediation work would be completed in the 2023 calendar year subject to rig availability and regulatory
approvals.
Offshore Otway Basin
The Company’s activities in the offshore Otway Basin comprise:
a)
offshore gas exploration, development and production
i. production licences VIC/L24 and VIC/L30 containing the producing Casino, Henry and Netherby gas fields (“Casino Henry”);
ii. production licences VIC/L33 and VIC/L34 containing part of the Black Watch gas field and Martha gas field;
iii. exploration permit VIC/P44, which contains the undeveloped Annie gas discovery, and VIC/P76.
All of these, except VIC/P76, are 50% interest held in joint ventures with Mitsui E&P Australia Pty Ltd and its associated entity Peedamullah
Petroleum Pty Ltd (collectively referred to hereafter as “Mitsui”), operated by Cooper Energy. VIC/P76 is held 100% and operated by
Cooper Energy.
b) a 50% interest in and Operatorship of the Athena Gas Plant, onshore Victoria, which is jointly owned with Mitsui.
The plant was acquired during the period to process gas from Casino Henry and other local discoveries such as Annie.
c) a 10% interest in the production licence VIC/L22 which holds the Minerva gas field and is held in the Minerva Joint Venture with the Operator
and remaining interest holder, BHP Petroleum. The field was shut-in during the period.
Offshore Otway production
Cooper Energy’s share of production from its offshore Otway interests was 1.0 million boe comprising 6.2 PJ of gas and 3,500 barrels of
condensate. This is lower than the FY19 production of 1.1 million boe (6.6 PJ of gas and 4,600 barrels of condensate) due to the cessation of
production from Minerva.
Production from the Casino Henry field increased, reflecting higher production rates achieved following the resumption of production for repair
and upgrade during the first quarter of the year.
Offshore Otway exploration
A two-well gas exploration program in the offshore Otway Basin was commenced in August 2019.
The first well, Annie-1 in VIC/P44, made a new gas field discovery, identifying a gross 70 metre gas column in the primary target Waarre C
formation with net gas pay thickness of 62 metres. A Contingent Resource assessment was issued to the ASX on 24 February and upgraded
in the statement of reserves and resources issued 31 August 2020. Annie is assessed to hold gross 2C Contingent Resources of 57.4 PJ, with
Cooper Energy’s equity share being 28.7 PJ. Development of the field is being assessed under the Otway Phase 3 Development Project discussed
under Offshore Otway development following.
Drilling of the second well in the program, Elanora-1 in VIC/L24, was deferred following repeated loss of tension on the mooring lines attached
to the Ocean Monarch drilling rig whilst on location at Annie-1. Drilling of Elanora-1 will be considered for a drilling campaign being planned to
commence in the latter half of 2022, subject to rig availability and joint venture approval.
1. Cooper Energy announced its assessment of the Manta Contingent Resource to the ASX on 12 August 2019. Cooper Energy is not aware of any
new information or data that materially affects the information provided in that release and all material assumptions and technical parameters
underpinning the assessment provided in the announcement continues to apply.
38
Operating and Financial Review
For the year ended 30 June 2020
Operations continued
The granting of the VIC/P76 permit during the year consolidated Cooper Energy’s offshore Otway acreage position around existing infrastructure
and added to the exploration prospect inventory. The permit adjoins the Annie gas discovery and Casino production licence and is traversed
by the Casino gas pipeline, which is to be connected to the Athena Gas Plant. Amplitude-supported prospects have been identified within
the permit. Subsurface analysis of these prospects has commenced with a view to identifying the preferred candidate for drilling in the
FY23 campaign.
Offshore Otway development
The Company is pursuing development opportunities to increase production, revenue generation and returns from the offshore Otway Basin:
• upgrade and connection of the idle Athena Gas Plant to create a low-cost gas hub
Cooper Energy, in joint venture with Mitsui, acquired the plant in December 2019 following the completion of operations at the depleted
Minerva gas field. The plant offers improved resource recovery, lower processing costs and ullage for incremental gas production, such as from
an additional development well at Henry or a new discovery such as Annie.
Detailed engineering and design was conducted over the remainder of the year, culminating in Final Investment Decision being taken on
the project in July 2020. The project involves upgrade of the plant and connection to the Company’s existing producing fields in the region
for a gross projected construction cost of $37 million (Cooper Energy share 50%). Gross expenditure prior to FID on acquisition and FEED was
$16 million.
First gas into the plant is scheduled for the September quarter 2021, including allowances for COVID related disruptions as presently understood.
• Otway Phase 3 Development Project
The Otway Phase 3 Development Project (OP3D) involves development of the Annie gas field and infill drilling of the Henry gas field to enable
production of approximately 100 PJ of gas via the Athena Gas Plant. OP3D is currently in the Concept Select phase. The project is scheduled
to complete this phase in the September quarter 2020 which incorporates allowances for COVID-19 impacts as it is presently understood.
It is possible further restrictions or supply chain disruption may cause delays to this schedule.
Development drilling required for OP3D could be incorporated into the broader drilling rig program planned to commence in the second half of
calendar 2022, enabling first gas from late in FY23.
Onshore Otway Basin
The Company’s interests in the onshore Otway Basin include licences in South Australia and permits in Victoria. Activities in the latter are
currently suspended pursuant to the Petroleum Legislation Amendment Act which extends a Victorian State Government moratorium on onshore
gas exploration until 30 June 2021. Conventional gas exploration in onshore Victoria can resume subsequent to that date.
The onshore Otway Basin interests comprise:
a) 30% interests in PEL 494, PRL 32 and PELA 680, South Australia.
The remaining interest in these joint ventures is held by the Operator, Beach Energy Limited. At year-end advice was received from the
South Australia government that a bid by Beach Energy Limited and Cooper Energy limited for block OT2019-B (renamed to PELA 680) was
successful. It is expected the exploration permit will be awarded in late 2020.
b) 50% interests in PEP 150 and PEP 168 in Victoria
The remaining interests in the PEP 150 and PEP 168 joint ventures are held respectively by the Operators, Bridgeport Energy Limited and
Beach Energy Limited.
c) 75% interest in PEP 171 in Victoria, which may reduce to 50% on fulfilment of farm-in arrangements executed with Vintage Energy Ltd who
hold 25% of the permit.
An exploration well, Dombey-1, was drilled in PEL 494 during the year and recorded a new gas field discovery, identifying a gross gas column of
44.5 metres with net pay thickness of 25 metres in the primary target Pretty Hill formation. A production test recorded initial rates exceeding
18 MMscf/d indicating good reservoir productivity. Subsequent decline in flow rates, followed by re-pressurisation, suggests Dombey-1DW1 has
drilled a small compartment partially connected to a broader accumulation.
The results of Dombey-1 have affirmed the prospectivity of the onshore Otway Basin and de-risked a number of prospects within PEL 494.
The joint venture is planning acquiring 3D seismic data to better understand the Dombey structure and adjacent prospects and better define
the Dombey appraisal plans.
Dombey-1 was part-funded through a $6.89 million PACE Gas Round 2 grant by the South Australian Government and is located 20 kilometres
north-west of the Katnook Gas Plant.
Cooper Basin
The Cooper Basin interests comprise:
a) 25% interest in PRLs 85-104 (the “PEL 92 Joint Venture”) with the remaining interest held by the Operator, Beach Energy Limited.
b) 30% interest in PRLs 231-233 (the “PEL 93 Joint Venture”), with the remaining interest in the joint venture held by the Operator, Senex
Energy Limited;
39
Operating and Financial Review
For the year ended 30 June 2020
Operations continued
c) 20% interest in PRL 237, with the remaining interests in the joint venture held by Metgasco Limited and the Operator, Senex Energy Limited;
d) 19.165% interest in PRLs 207-209 (formerly PEL 100), with the remaining interests in the joint venture held by Santos QNT Pty Ltd and the
Operator, Senex Energy Limited; and
e) 20% interest in PRLs 183-190 (formerly PEL 110), with the remaining interest in the joint venture held by the Operator, Senex Energy Limited.
Exploration and development
A total of 16 wells were drilled by the PEL 92 Joint Venture during the year. The program included 13 appraisal wells, 1 development well and
2 exploration wells. Three appraisal wells were cased and suspended as future oil producers with all other wells being plugged and abandoned.
Financial Performance
Cooper Energy Limited recorded a statutory loss after tax of $86.0 million for the financial year which compares with the loss after tax of
$12.1 million recorded in the 2019 financial year. The 2020 financial year statutory loss included a number of items which affected the result by a
total of $79.4 million. These items comprise:
• liquidated damages income of $19.8 million received from APA as a consequence of the delay to the commencement of gas production from
the Orbost Gas Processing Plant;
• a non-cash restoration expense of $14.1 million resulting from a reassessment of the Patricia Baleen field restoration provision and Minerva
field restoration provision;
• a non-cash impairment expense of $107.5 million; and
• tax impact of the above items of $22.4 million
The prior period result included a non-cash restoration expense of $26.2 million and a gain on exit provision of $0.8 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 $29.6 million was 14% lower than the prior comparative period figure of $34.3 million. This reduction has impacted
underlying profit after tax in addition to the impact of increased depreciation and amortisation, exploration and evaluation expense and tax.
The underlying loss after tax (exclusive of the items noted above) was $6.6 million, compared with an underlying profit after tax of $13.3 million
in the 2019 financial year. The factors which contributed to the movement between the periods were:
• higher gas sales revenue of $2.6 million attributed to Sole gas sales, improved performance of the Casino Henry wells and higher contracted
gas prices. This was partially offset by decline in oil sales volumes and price;
• higher costs of sales of $11 million; largely due to non-cash factors. Amortisation and depreciation was $8.5 million higher primarily due to
increases in future development costs of undeveloped proved and probable reserves and early cessation of the Minerva Field. Gas processing
costs and royalties were $2.5 million higher;
• higher net finance costs of $4.3 million due to cessation of interest capitalised on the Sole Oil and Gas asset;
• higher care and maintenance costs of $3.0 million and other costs of $2.8 million; and
• higher exploration and evaluation write off of $1.7 million attributable to unsuccessful wells in the Cooper Basin and costs associated with the
deferred Elanora well in the offshore Otway basin.
Financial Performance
FY20
FY19
Change
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)/profit after tax
Underlying (loss)/profit before tax
Underlying EBITDAX*
MMboe
$ million
$ million
%
$ million
$ million
$ million
$ million
$ million
$ million
1.5
78.1
23.6
30.2
48.1
132.1
(86.0)
(6.6)
(30.5)
29.6
1.3
75.5
31.7
42.0
20.5
165.5
(12.1)
13.3
12.1
34.3
0.25
2.6
(8.1)
(11.8)
27.6
(33.4)
(73.9)
(19.9)
(42.6)
(4.7)
* Earnings before interest, tax, depreciation, amortisation, restoration, exploration and evaluation expense and impairment
%
19%
3%
(25%)
(28%)
134%
(20%)
(611%)
(150%)
(352%)
(14%)
40
Operating and Financial Review
For the year ended 30 June 2020
Financial Performance continued
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 $32.7 million over the period as summarised in the following chart.
Operating cashflows for the period were $48.1 million comprising:
• cash generated from operations of $40.3 million;
• liquidated damages of $19.8 million received as a consequence of the delay to the commencement of gas production from the Orbost Gas
Processing Plant disclosed as a significant item above;
• general administration costs of $11.3 million;
• restoration costs of $2.5 million;
• Petroleum Resource Rent Tax (PRRT) receipts of $4.1 million as a result of transferable exploration credits; and
• net interest paid of $2.3 million;
Financing, investing and other cash flows for the period were $80.8 million and included:
• debt drawdowns of $11.0 million;
• interest payments of $9.7 million;
• exploration, development and property, plant and equipment costs of $81.7 million, mainly in relation to the drilling of Annie-1, Dombey-1,
and Cooper Basin appraisal wells. Other items in this category included payments made on the Minerva Gas Plant acquisition and for the Sole
Gas Project; and
• foreign exchange differences and other of $0.4 million.
$ million
Total cash and
cash equivalents,
other financial
assets and
investments
165.5
Other
financial
assets and
investments
40.3
1.2
164.3
Cash and
cash
equivalents
Movements in cash and cash equivalents
2020 vs 2019
+113.6
19.8
(11.3)
(2.5)
4.1
(2.3)
(11.0)
(9.7)
Total cash and
cash equivalents,
other financial
assets and
investments
132.2
(81.7)
Other financial
assets and
investments
(0.4)
0.6
212.4
131.6
Cash and
cash
equivalents
Operating
48.1
Other
(80.8)
June -19 Operations Liquidated
damages
General
admin
Restoration
costs
PRRT
Net
Interest
Cash after
operating
cash
flows
Net
debt
draw-
downs
Interest
payments
E & D
FX &
Other
June-20
41
Operating and Financial Review
For the year ended 30 June 2020
Financial Position
Financial Position
Total assets
Total liabilities
Total equity
Net debt
Assets
$ million
$ million
$ million
$ million
FY20
1,029.9
678.8
351.1
97.8
FY19
1,001.8
568.1
433.7
53.9
Change
28.1
110.7
(82.6)
43.9
%
3%
19%
(19%)
81%
Total assets increased by $28.1 million from $1,001.8 million to $1,029.9 million.
At 30 June the Company held cash and cash equivalents of $131.6 million and investments of $0.6 million.
Exploration and evaluation assets increased by $6.8 million from $152.3 million to $159.1 million as a result of increases associated with the reset
of the rehabilitation provisions and capital expenditure incurred on exploration assets, offset by impairment within the BMG, VIC/P44, PEL 92 and
the Onshore Otway permits.
Oil and gas assets increased by $2.8 million from $613.2 million to $616.0 million mainly as a result of capital expenditure incurred on
development activities and increases associated with the reset of the rehabilitation provisions, offset by impairment on Casino Henry.
The impairments arose from review of asset carrying values and provisions in light of lower gas and oil prices in post-COVID-19 markets and
intelligence acquired during the year on drilling, development and restoration and abandonment costs. The review incorporated revised
assumptions for oil and gas prices and exchange rates based on current and expected values. Price assumptions for uncontracted gas have been
revised to reflect expectations as at June 2020 for future term gas sales.
Total Liabilities
Total liabilities increased by $110.7 million from $568.1 million to $678.8 million.
Provisions increased by $106.7 million from $287.9 million to $394.6 million attributable to the revised gross cost assumptions for restoration
provisions and lower discount rates.
Interest bearing loans and borrowings increased by $15.7 million from $213.7 million to $229.4 million. This represents the drawdowns under the
reserve-based lending (RBL) facility.
Total Equity
Total equity decreased by $82.6 million from $433.7 million to $351.1 million. In comparing equity at 30 June 2020 to 30 June 2019 the key
movements were:
• higher contributed equity of $1.5 million due to shares issued on vesting of performance rights and share appreciation rights during the period;
• higher reserves of $1.9 million mainly due to the vesting of equity incentives to employees partially offset by fair value movements in the
Company’s interest rate swaps for which cash flow hedge relationships apply; and
• higher accumulated losses of $86.0 million due to the statutory loss for the period.
Outlook
The Company expects substantially increased production and sales in the 12 months to 30 June 2021 as a result of a full year contribution from
the Sole gas field. The extent of this increase will depend upon the timing and rate of build-up of production at the Orbost Gas Processing Plant,
which is still undergoing commissioning.
As an indication, the total production from all operations in FY20 averaged 4.275 kboe/day. This compares to approximately 6.5 to 7 kboe/day
from Sole alone at the rate of approximately 40 - 45 TJ/day maintained by the plant in late June to early July 2020. Achievement of plant
nameplate capacity represents an increment to these rates of 23 TJ to 28 TJ/day, or another 3.7 to 4.5 kboe/day. This goal is being pursued by the
ongoing optimisation of operations and Phase 2 plant works being planned by APA and Cooper Energy as discussed earlier under the heading
‘Sole Gas Project’. Ongoing technical analysis on the cause of the foaming within the plant (discussed on page 37) may also identify avenues
for improvement of plant performance. The average daily rates over the course of the year may be affected by shutdowns for modifications
or maintenance.
Other operations are expected to contribute approximately 2.6 kboe/day in FY21. Gas production of between 4 to 5 PJ is anticipated from the
offshore Otway (6 PJ in FY20), lower than FY20 due to the impact of shutdowns for maintenance of the Iona Gas Plant and, later in the year, for
connection to the Athena Gas Plant. Crude oil production from the Cooper Basin of 0.2 million barrels is expected (0.2 million barrels in FY20).
Capital expenditure of between $50 million and $58 million is anticipated in FY21 with plans concentrated on the offshore Otway operations,
most particularly the Athena Gas Project. It is intended to progress the OP3D and Manta-3 projects through the Select stage and towards FID
by the conclusion of FY21. The results of this work, together with well planning and subsurface studies on exploration targets in the Otway and
Gippsland Basins is expected to determine the composition of an offshore drilling program planned to commence, subject to rig availability in
the first half of FY23. Two development wells are planned for the Cooper Basin.
42
Operating and Financial Review
For the year ended 30 June 2020
Business Strategies and Prospects
Two premises underly the Company’s gas strategy: first, south-east Australia will require new sources of gas supply to replace declining
production from existing sources; and second, the most competitive source of supply for the region is gas produced in the region.
Accordingly, the Company’s strategy for the generation of shareholder wealth entails ownership and operation of a portfolio of gas assets with
superior competitiveness for the supply opportunities foreseen in south-east Australia. To this end, the Company has accumulated a portfolio of
gas assets occupying favourable positions on the cost curve for delivered gas to its markets and a portfolio of supply contracts with utility and
industrial customers.
FY20 saw short term disruption to energy market supply balances and a reaffirmation of the medium to long term merit of the Company’s
strategy and asset portfolio.
The surplus of international LNG supply relative to demand and lower economic activity levels during the year resulted in increased availability
of gas and lower spot prices. This situation has continued into FY21. Analysis by the Company and by the Australian Energy Market Operator
has reaffirmed the premise of the Company’s gas strategy, anticipating a widening gap between local demand and depleting local supply from
FY22 onwards.
The Company is well-positioned for both the near and longer terms by virtue of its gas contract portfolio and the competitiveness of its asset
base in comparison with other potential sources of supply. The Company’s contracted gas is committed under take-or-pay terms, without oil price
linkage, to provide assurance of cash flow.
Looking to the longer term, the Company expects to generate wealth through supplying into an increasingly tight south-east Australian gas
market from its uncontracted reserves, resources and that identified through exploration. During FY21 and FY22 the Company anticipates
executing business plans to increase its exposure to the favourable south-east Australian gas market anticipated in the medium term.
These plans include:
• the Athena Gas Plant project. Apart from establishing a low-cost processing hub for Otway Basin gas, the project will permit gas from Casino
Henry to be contracted on a firm supply basis;
• definition of an economic development project for undeveloped gas in the Henry and Annie gas fields through the OP3D project;
• commitment to the drilling of the Manta-3 appraisal and exploration well. Development of Manta is contingent on the outcomes of the
Manta-3 well; and
• identification of preferred targets for exploration for new resources of gas in the Otway and Gippsland basins. The Company’s acreage in
these regions holds identified gas prospects in proximity, and on-trend with, producing and known gas fields and close to existing pipe and
processing infrastructure. These are to be targeted in the drilling campaign being planned for FY23.
The Company is vigilant in identifying potential value-creation opportunities from participation in assets that fit with the Company’s capabilities,
strategy and portfolio. The Company reviews its portfolio and equity participation levels on an ongoing basis for optimal allocation of capital for
value creation.
Funding and Capital Management
Cooper Energy seeks to manage its capital with the objective of providing shareholders with the optimal risk-weighted return from the
application of its expertise in the exploration, development, production and sale of hydrocarbons.
At 30 June 2020 the Company had cash, deposits, and equity instruments of $131.6 million and drawn debt of $229.4 million. The Company has
a Reserve Based Lending facility to fund a portion of the Sole gas field development with a limit of $250.0 million. Of this limit, $233.0 million
is available, of which $3.6 million remains undrawn at 30 June 2020. 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 $1.5 million has been utilised in respect of bank guarantees with the remaining balance undrawn. Further
information is detailed in the Going concern basis section on page 78 and Note 18 of the Financial Statements.
The Company continues to assess value accretive funding options as it pursues growth opportunities.
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
perform risk assessments on a regular basis and a summary is reported to the Risk and Sustainability Committee. The Committee approves and
oversees an internal audit program undertaken internally and/or in conjunction with appropriate external industry or field specialists.
COVID-19
Cooper Energy responded 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.
• assessing, monitoring and managing risks to the continuity of the business.
43
Operating and Financial Review
For the year ended 30 June 2020
Risk Management continued
A Pandemic Response Team was established and resourced to include input from an independent medical practitioner, reporting to the
Managing Director to oversee the company’s response. That response included implementing robust work from home arrangements
with on-site staffing requirements limited to minimal IT support attendance when required at office locations and a skeleton staff at the
Cooper Energy operated Athena Gas Plant. The work from home arrangements were used in Adelaide and Perth during the period
March – May 2020, and contingencies are in place to rapidly reinstate them if required. The Athena Gas Plant upgrade continues with limited
on-site manning and specific risk controls in place.
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 were tested using fully remote processes during the period.
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 through 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 to the pandemic.
Appropriate policies and procedures are continually being developed and updated to manage these risks.
Risk
Description
Exploration
Development and
Production
Regulatory
Market
44
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 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.
All major development investment decisions are subjected to assurance reviews which includes external experts and
contractors where appropriate.
Cooper Energy operates in a highly regulated environment and complies with regulatory requirements. There is a
risk that regulatory approvals are withheld, take longer than expected or unforeseen circumstances arise where
requirements may not be adequately addressed in the eyes of the regulator and costs may be incurred to remediate
non-compliance and/or obtain approval(s). Changes in personnel, Government, monetary, taxation and other laws
in Australia or internationally may impact the Company’s operations.
Cooper Energy monitors legislative and regulatory developments and works to ensure that stakeholder concerns
are addressed fairly and managed. Documents submitted to regulatory authorities are reviewed and audited to
help ensure they are appropriate and comply with all regulatory requirements.
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 its 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 4 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 favorable 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 market 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 its market of south-east Australia.
The Company’s portfolio management and investment strategy expressly focus on assets with a foreseeable
pathway to commercialisation within the medium term to remove the risk of exposure to assets becoming stranded
by unforeseen developments in long term investment horizons.
Operating and Financial Review
For the year ended 30 June 2020
Risk Management continued
Risk
Description
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.
Operating
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 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 FY20 to reflect risks associated with COVID-19) and an HSEC management system to ensure safe
and sustainable operations.
Counterparties
The ability of Cooper Energy to achieve its stated objectives will depend on the performance of the counterparties
under various agreements it has entered into (including joint venture arrangements). If any counterparties do not
meet their obligations under the respective agreements, this may impact on operations, business and
financial conditions.
Reserves
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. The Company’s gas
contracting strategy expressly focusses on financially robust organisations assessed as being reliable gas
consumers within the energy markets forecast by the Company’s, and third party, research.
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.
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.
Funding
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 expenditures in order to conduct its development appraisal and
exploration activities. Limitations on the 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 debt and equity funding. There can be no assurance that
sufficient debt or equity funding will be available on acceptable terms or at all.
Cooper Energy endeavours to ensure 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.
45
Operating and Financial Review
For the year ended 30 June 2020
Risk Management continued
Risk
Description
Community
Cooper Energy conducts exploration and production operations in regions with residential, environmental, cultural
and economic significance to local and national communities. Loss of confidence in the Company, in its ability
to operate responsibly or opposition to exploration and production activities generally within these communities
may adversely affect community sentiment towards Cooper Energy and impact its capacity to execute its plans.
Cooper Energy conducts a community engagement programme at multiple levels and in multiple forms.
The purpose of this programme is to build and maintain awareness, understanding and support of the Company,
its operations and plans in the local regions. It serves to build long term positive relationships with local
communities together with awareness of the economic benefits to the community and the nation generally.
Elements of the program include:
•
•
•
•
sponsorship and donations made to local community organisations;
engagement and briefing with local office holders and elected representatives of local, state, and federal government.
engagement with local community groups via town hall meetings and community information sessions;
engagement with fishing industry associations;
• 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.
Climate and
Sustainability
Cooper Energy 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 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”)
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 expressed investment 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 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.
The merits of gas as a clean-burning energy source, and as a necessary backstop of dispatchable power for
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
in its annual Sustainability Report (the first of which was published in October 2019).
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.
The Company measures, monitors and reports on its emissions and seeks to reduce its emissions impact. These
results are published in its annual Sustainability Report.
46
Operating and Financial Review
For the year ended 30 June 2020
Reconciliations for net profit/(loss) to Underlying net profit/(loss) and Underlying EBITDAX
Reconciliation to Underlying profit/(loss)
Net profit/(loss) after income tax
Adjusted for:
Gain on exit provision
Liquidated damages
Restoration expense
Impairment
Tax impact of underlying adjustments
Underlying (loss)/profit
Reconciliation to Underlying EBITDAX*
Underlying (loss)/profit
Add back:
Tax impact of underlying adjustments
Net interest expense/(revenue)
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
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
FY19
(12.1)
Change
%
(73.9)
(611%)
(0.8)
-
26.2
-
-
13.3
FY19
13.3
-
(3.4)
5.0
(1.2)
1.0
18.2
1.4
34.3
0.8
(19.8)
(12.1)
107.5
(22.4)
(19.9)
100%
(100%)
(46%)
100%
(100%)
(150%)
Change
%
(19.9)
(150%)
22.4
5.2
(1.0)
(22.7)
1.3
8.3
1.7
(4.7)
100%
153%
(20%)
(1892%)
130%
46%
121%
(14%)
* Earnings before interest, tax, depreciation, amortisation, restoration, exploration and evaluation expense and impairment
The adoption of AASB 16 Leases in the period means that the FY20 results have a higher portion of depreciation and interest charge and lower
SG&A costs. This increases the current year EBITDAX by $1.7 million relative to the prior year.
47
Directors’ Statutory Report
For the year ended 30 June 2020
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 2020, 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
Mr Timothy G. Bednall
LLB (Hons)
Independent Non-Executive
Director
Appointed 31 March 2020
subject to confirmation
by shareholders at the
Company’s 2020 AGM
48
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 President
of the Commonwealth Remuneration Tribunal (since 2003) and a Director of Dexus Property Group ASX:
DXS (since 2009). He is Deputy Chairman of Whitehaven Coal Limited ASX: WHC (since 2007). Mr Conde
is a former Chairman of Bupa Australia (2008 – 2018).
Special responsibilities
Mr Conde is Chairman of the Board of Directors. He is also a member of the People and Remuneration
Committee and is the Chairman of the 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 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 (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).
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).
Special responsibilities
Mr Bednall is a member of the People & Remuneration Committee, the Nomination Committee and the
Risk & Sustainability Committee.
Director’s Statutory Report
For the year ended 30 June 2020
1. Directors continued
Ms Victoria J. Binns
B. Eng (Mining – Hons 1),
Grad Dip SIA, FAusIMM, GAICD
Independent Non-Executive
Director
Appointed 2 March 2020
subject to confirmation
by shareholders at the
Company’s 2020 AGM
Ms Elizabeth A. Donaghey
B.Sc., M.Sc.
Independent Non-Executive
Director
Appointed 25 June 2018
Experience and expertise
Ms Binns has over 35 years’ experience in the global resources and financial services sectors including more
than 10 years in executive leadership roles at BHP and 15 years in financial services with Merrill Lynch
Australia and Macquarie Equities. During her career at BHP, Ms Binns’ roles included Vice President Minerals
Marketing, leadership positions in the metals and coal marketing business, Vice President of Market
Analysis and Economics and was a member of the first BHP Global Inclusion and Diversity Council.
Prior to joining BHP, Ms Binns held a number of board and senior management roles at Merrill Lynch
Australia including Managing Director and Head of Australian Research, Head of Global Mining, Metals and
Steel, and Head of Australian Mining Research. She was also co-founder and Chair of Women in Mining
and Resources Singapore.
Current and other directorships in the last 3 years
Ms Binns is currently a Non-Executive Director of ASX-listed company Evolution Mining (since 2020).
Special responsibilities
Ms Binns is a member of the Audit Committee, the People & Remuneration Committee and the Risk and
Sustainability Committee.
Experience and expertise
Ms Donaghey brings over 30 years’ experience in the energy sector including technical, commercial and
executive roles in EnergyAustralia, Woodside Energy and BHP Petroleum.
Ms Donaghey’s experience includes Non-Executive Director roles at Imdex Ltd (an ASX-listed provider of
drilling fluids and downhole instrumentation), St Barbara Ltd (a gold explorer and producer), and the
Australian Renewable Energy Agency. She has performed extensive committee roles in these
appointments, serving on audit and compliance, risk and audit, technical and regulatory, remuneration
and health and safety committees.
Current and other directorships in the last 3 years
Ms Donaghey is a Non-Executive Director of the Australian Energy Market Operator (AEMO) (since 2017).
Special responsibilities
Ms Donaghey is a member of the Risk and Sustainability Committee, the People and Remuneration
Committee and the Nomination Committee.
Mr Hector M. Gordon
B.Sc. (Hons)
Independent Non-Executive
Director
26 June 2012 – 23 June 2017
Non-Executive Director
Appointed 24 June 2017
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 Gordon is the Chairman of the Risk and Sustainability Committee and a member of the
Audit Committee.
Mr Jeffrey W. Schneider
B.Com
Independent Non-Executive
Director
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
Mr Schneider is Chairman of the People and Remuneration Committee, and a member of the Nomination
Committee and the Audit Committee.
49
Director’s Statutory Report
For the year ended 30 June 2020
1. Directors continued
Ms Alice J. Williams
B.Com, FAICD, FCPA, CFA
Independent Non-Executive
Director
Appointed 28 August 2013
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 Equity Trustees Ltd ASX: EQT (since 2007), Djerriwarrh
Investments Ltd, Defence Health (since 2010) and not for profit Tobacco Free Portfolios (since 2018).
Ms Williams has recently stepped down as a Member of the Foreign Investment Review Board.
Ms Williams was a Non-Executive Director of the Victorian Funds Management Corporation for the
period 2008 to 2018.
Special responsibilities
Ms Williams is the Chairman of the Audit Committee and a member of the Risk and
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 19 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, the UK and South East Asia in roles with Repsol, Talisman Energy, King & Spalding LLP and Santos.
Ms Alison Evans B.A., LLB held the position of Company Secretary and Legal Counsel from 25 February 2013 to 9 August 2019. Ms Evans
concluded her employment with Cooper Energy on 20 December 2019.
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
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
8
8
2
2
8
8
8
8
B
8
8
2
2
8
8
8
8
A = Number of meetings attended.
Audit
Committee
Meetings
Risk &
Sustainability
Meetings
People &
Remuneration
Committee
Meetings
Nomination
Committee
Meetings
A
-
-
-
1
3
4
4
4
B
-
-
-
1
3
4
4
4
A
-
-
-
-
3
3
-
3
B
-
-
-
-
3
3
-
3
A
4
-
1
1
4
-
4
-
B
4
-
1
1
4
-
4
-
A
1
1
-
-
1
1
1
1
B
1
1
-
-
1
1
1
1
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 restructured with effect as of 1 May 2020).
* Mr Bednall was appointed 31 March 2020.
** Ms Binns was appointed 2 March 2020.
50
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report (audited)
Information about the remuneration of the Company’s key management personnel for the financial year ended 30 June 2020 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
and Remuneration Committee
Dear Shareholder
I am pleased to present your Company’s 2020 Remuneration Report for which we will be seeking your support at the 2020 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, details the remuneration outcomes for its Board and key management personnel, and enables comparison of these
remuneration outcomes with the Company’s performance.
The People and Remuneration Committee’s view is that this report shows the Company’s remuneration framework to be appropriate, and that
the 2020 remuneration outcomes are fair when compared to peer companies and taking account of the Company’s performance over the last
few years.
Remuneration Report context: 2020 Financial Year
The Company’s performance in the 12 months to 30 June 2020 is reported in the Operating and Financial Review of the Financial Report.
This performance and how it compared to the specific targets of the Company Scorecard provide the context of the Remuneration Report.
Cooper Energy met or exceeded the targets of its Corporate Scorecard in the categories of HSEC, Growth and People & Enablers. The Company
failed to meet target in the areas of Production & Revenue and Project Delivery.
The Company’s share price decreased by 31% over the 2020 financial year. Notably however Cooper Energy has outperformed most of the
peer company set (but not all) on a 1 year basis and has outperformed all on a 5 year basis.
A remuneration framework which attracts, encourages, rewards and retains talent is an important foundation that can enable the company to
repeat superior total shareholder return and the share price growth that is essential for your Company’s ongoing development.
Remuneration developments
The Company’s remuneration framework has been stable for some time. The view of the People and Remuneration Committee is that the
Company’s remuneration framework and principles have served the Company well. They are simple and relevant and consistent with the
objective to attract and retain high calibre employees and provide incentives to deliver superior performance in line with the Cooper Energy
Values. Consequently, there has been little change to the Company’s remuneration structure and no change is proposed for the 2021
financial year.
Cognisant of community and investor expectations, particularly in light of the economic impact of the COVID-19 pandemic, there is no change
in fees payable to Directors proposed for FY21. I confirm that Directors’ fees remain comparable with relevant peer companies. For the same
reasons, and consistent with benchmarking within the hydrocarbon industry, the Fixed Annual Remuneration of our Managing Director and
Executive Leadership Team will not increase in FY21.
Remuneration outcomes
The remuneration outcomes detailed in this report are consistent with and recognise the performance of the Company over both the short and
long terms. In response to feedback, we have included full year STIP awards paid for FY20. Important components of the Corporate Scorecard
that relate to Production and Revenue and also those relating to Growth Projects have been significantly impacted by the late start-up of the
onshore gas plant at Orbost. As a consequence, the Board has assessed the Corporate Scorecard result as being 39/100.
This past year has presented many challenges for our shareholders, our staff and the many consultants that support us, and of course for
their families. The COVID-19 pandemic has also tested how we all work together. Cooper Energy has continued to work in a very focused yet
collaborative manner throughout. We thank the Managing Director, the Executive Leadership Team and their teams for their very considerable
commitment and contribution over the year.
Yours sincerely
Mr Jeffrey Schneider
Chairman of the People and Remuneration Committee
51
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report 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 2020 Executive KMP Performance and Remuneration Outcomes
4.7 Executive KMP Employment Contracts
4.8 2020 Remuneration Outcomes for Executive KMP
4.9 Nature of Non-Executive Director Remuneration
Page
52
52
53
54
60
61
63
64
68
4.1 Introduction
This Remuneration Report (Report) details the approach to remuneration frameworks, outcomes and performance for Cooper Energy.
The Remuneration Report forms part of the Directors’ Report and provides shareholders with an understanding of the remuneration principles
and practices in place for Key Management Personnel (KMP) for the reporting period.
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 Directors
Mr J. Conde AO
Ms E. Donaghey
Mr H. Gordon
Mr J. Schneider
Ms A. Williams
Ms V. Binns1
Mr T. Bednall1
Position
Chairman
Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director
Period KMP
1 July 2019 to 30 June 2020
1 July 2019 to 30 June 2020
1 July 2019 to 30 June 2020
1 July 2019 to 30 June 2020
1 July 2019 to 30 June 2020
Non-Executive Director (casual vacancy)
2 March 2020 to 30 June 2020
Non-Executive Director (casual vacancy)
31 March 2020 to 30 June 2020
1. Ms Binns and Mr Bednall were each appointed to a casual vacancy as a Non-Executive Director on the respective dates above.
Their appointments are to be confirmed by shareholders at the 2020 Annual General Meeting scheduled for 12 November 2020.
Executive KMP
Mr D. Maxwell
Mr A. Thomas
Ms V. Suttell
Ms A. Jalleh¹
Mr I. MacDougall
Mr E. Glavas
Mr M. Jacobsen
Position
Managing Director
Period KMP
1 July 2019 to 30 June 2020
General Manager Exploration & Subsurface
1 July 2019 to 30 June 2020
Chief Financial Officer
1 July 2019 to 30 June 2020
Company Secretary and General Counsel
9 August 2019 to 30 June 2020
General Manager HSEC & Technical Services
1 July 2019 to 30 June 2020
General Manager Commercial & Development
1 July 2019 to 30 June 2020
General Manager Projects & Operations
1 July 2019 to 30 June 2020
1. Ms Jalleh was appointed to the role of Company Secretary and General Counsel on 9 August 2019.
52
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.2 Key Management Personnel covered in this Report continued
Former Executive KMP
Position
Period KMP
Ms A. Evans1
Mr D. Clegg2
Company Secretary and Legal Counsel
1 July 2019 to 9 August 2019
General Manager Development
1 July 2019 to 31 December 2019
1. Ms Evans ceased being Company Secretary and General Counsel on 9 August 2019. Ms Evans concluded her employment with
Cooper Energy on 20 December 2019.
2. Mr Clegg ceased being a member of the Executive Leadership Team on 31 December 2019 (he now has a part-time role with the Company).
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 hydrocarbon 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 and Remuneration Committee
The People and Remuneration Committee (which is comprised of 5 Non-Executive Directors, all of whom are independent) makes
recommendations to the Board about remuneration strategies and policies for the Executive KMP and considers programs related to executive
development and talent management.
On an annual basis, the People and 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 hydrocarbon industry remuneration data.
53
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report 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 (FAR)
Short Term Incentive Plan (STIP)
Long Term Incentive Plan (LTIP)
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 FY21.
54
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.4 Nature & Structure of Executive KMP Remuneration continued
4.4.2 Remuneration strategy and framework – Overview
Fixed Annual
Remuneration
Salary and other
benefits (including
statutory
superannuation)
Short Term
Incentive Plan
(STIP)
Annual incentive
opportunity
delivered in cash
based on Company
and individual
performance
Performance Conditions
Key Considerations
• Scope of individual’s role
• Individual’s level of knowledge, skills and expertise
• Individual performance
• Market benchmarking
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.
Remuneration Strategy/Performance Link
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.
55
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.4 Nature & Structure of Executive KMP Remuneration continued
4.4.2 Remuneration strategy and framework – Overview 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 hydrocarbon 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 Company performance measures in the Company’s scorecard and weightings are
as follows:
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
56
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.4 Nature & Structure of Executive KMP Remuneration continued
4.4.4 Short Term Incentive Plan (STIP) - Overview continued
Performance Measures
Rationale
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 and
• Front End Engineering & Design and Final
budget, with appropriate contingency included
Investment Decisions
• Clear management systems
• Consistent successful major project delivery
Growth (20%)
• Reserves
Targeting:
• Gas marketing
• Acquisitions & divestments
• Development projects per schedule and adding economic value
• Term gas contracts that underpin new business and add value
(in each case to reflect a growing business)
• 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
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
57
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.4 Nature & Structure of Executive KMP Remuneration continued
4.4.4 Short Term Incentive Plan (STIP) - Overview continued
The key features of the STIP for the FY2020 are as follows:
STIP FY20 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.
What is the maximum award
opportunity (% of Fixed Remuneration)?
Managing Director
Other Executive KMP
100%
50%
What is the performance period?
How are the performance
measures determined and what are
their relative weightings?
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 FY20. 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. These relate to the individual’s performance in achieving things such as business unit
objectives, promotion of the Cooper Energy Values and identified areas for development.
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.
58
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.4 Nature & Structure of Executive KMP Remuneration 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 2020 financial year (granted December 2019) are set out in the following table:
FY20 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 has 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, such as the Sole
development. 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.
59
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.4 Nature & Structure of Executive KMP Remuneration continued
4.4.5 Long Term Incentive Plan (LTIP) - Overview continued
FY20 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
2021 financial year?
It is not anticipated that the general structure of the LTIP will change for grants made in FY21.
However, the Board will continue to review the appropriateness of the performance measures as the
Company transitions from development to gas production and sale.
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
0.46
3.0
11.7
52.4
52.7
49.9
FY16
FY17
FY18
FY19
FY20
FY16
FY17
FY18
FY19
FY20
Links directly to Company STIP reward outcomes as an
Operational & Financial KPI.
Links directly to Company STIP reward outcome as a Growth KPI.
Total Recordable Incident Frequency Rate
(events per hours worked)
Sales Revenue ($ million)
4.07
3.53
1.98
27.4
39.1
67.5
75.5
78.1
0.0
FY16
FY17
FY18
0.0
FY19
FY20
FY16
FY17
FY18
FY19
FY20
Links directly to Company STIP reward outcome as a Safety
& Sustainability KPI.
Links directly to Company STIP reward outcome as an
Operational & Financial KPI.
60
Financial – Profit After Tax ($ million)
Financial – Earnings Per share (cents)
27.0
-12.3
-12.1
-34.8
-10.1
1.8
-1.8
-0.7
-5.3
FY16
FY17
FY18
FY19
FY16
FY17
FY18
FY19
FY20
Links directly to Company STIP reward outcome as an Operational
Links directly to Company LTIP reward outcome by increasing
& Financial KPI through cost management.
shareholder value.
Financial – Total Shareholder Return (%)
Capital As At 30 June Share Price ($ per share)
72.7
40.3
6.0
0.38
0.39
0.375
0.54
0.22
-12.2
FY16
FY17
FY18
FY19
FY16
FY17
FY18
FY19
FY20
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.
-86.0
FY20
-30.6
FY20
Capital As At 30 June – Market Capitalisation ($ million)
875.6
616.4
610.0
433.4
93.6
FY16
FY17
FY18
FY19
FY20
Links directly to Company LTI reward outcome by increasing
shareholder value compared to peers.
Annual Production (MMboe)
Proved & Probable Reserves (MMboe)
1.49
1.31
1.50
0.96
0.46
3.0
11.7
52.4
52.7
49.9
FY16
FY17
FY18
FY19
FY20
FY16
FY17
FY18
FY19
FY20
Links directly to Company STIP reward outcomes as an
Links directly to Company STIP reward outcome as a Growth KPI.
Operational & Financial KPI.
Total Recordable Incident Frequency Rate
(events per hours worked)
Director’s Statutory Report
For the year ended 30 June 2020
4.07
3.53
1.98
Sales Revenue ($ million)
67.5
75.5
78.1
27.4
39.1
0.0
FY16
FY17
FY18
0.0
FY19
FY20
FY16
FY17
FY18
FY19
FY20
4. Remuneration Report continued
Links directly to Company STIP reward outcome as a Safety
& Sustainability KPI.
Links directly to Company STIP reward outcome as an
Operational & Financial KPI.
4.5 Cooper Energy’s Five-Year Performance and Link to Remuneration continued
Financial – Profit After Tax ($ million)
Financial – Earnings Per share (cents)
27.0
-12.3
-12.1
-34.8
FY16
FY17
FY18
FY19
-86.0
FY20
-10.1
1.8
-1.8
-0.7
-5.3
FY16
FY17
FY18
FY19
FY20
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 (%)
Capital As At 30 June Share Price ($ per share)
72.7
40.3
6.0
-12.2
FY16
FY17
FY18
FY19
-30.6
FY20
0.38
0.39
0.375
0.54
0.22
FY16
FY17
FY18
FY19
FY20
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.
Capital As At 30 June – Market Capitalisation ($ million)
875.6
616.4
610.0
433.4
93.6
FY16
FY17
FY18
FY19
FY20
Links directly to Company LTI reward outcome by increasing
shareholder value compared to peers.
In FY20 and in the past 5 years dividends were not paid by the Company to its shareholders, nor was there a return of capital by the Company to
its shareholders. However, Cooper Energy recorded a superior total shareholder return when compared to the large majority of its peers in both
the short and long-term assessment periods. While the Company’s share price decreased by 31% over the 2020 financial year, it has increased
1.8 times (share price increase of 83%) in the 5 years to 30 June 2020. Cooper Energy has outperformed most of its peer set on a 1 year basis and
all on a 5 year basis.
4.6 2020 Executive KMP Performance and Remuneration Outcomes
4.6.1 Fixed Annual Remuneration outcome
The Fixed Annual Remuneration for the Managing Director and other Executive KMP were reviewed at the end of the FY20 financial year. No
increases to Fixed Annual Remuneration were awarded as a result of this review.
During FY20 Executive KMP Fixed Annual Remuneration increases were in the range of 2.86% - 7.59%, reflecting industry benchmarking and in
line with the Company’s remuneration strategy. The scope of the roles of some Executive KMP also materially increased in FY20.
4.6.2 STIP performance outcomes – Company Results
The Company Scorecard results for the reporting period ranged between Threshold and Stretch and cover the full FY20.
The Company’s FY20 result was a score of 39 out of 100.
61
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.6 2020 Executive KMP Performance and Remuneration Outcomes continued
4.6.2 STIP performance outcomes – Company Results continued
Company Scorecard Results FY20
Performance
Measure
(Weighting %)
HSEC (20%)
Production &
Revenue (20%)
Project Delivery
(20%)
Growth (20%)
People, Culture &
Enablers (20%)
FY20 Performance:
Threshold
Target
Stretch
Super
Stretch
Performance Measure Outcome
TRIFR 3.39. No reportable environmental incidents.
Community relationships enhanced. COVID-19
managed well.Assessed Score: 12/20
Production of 1.52 MMboe
Assessed Score: 0/20
Sole offshore within schedule and budget. Delays at
Orbost Gas Processing Plant. Athena Gas Plant FID.
Assessed Score: 2/20
Annie success. Successful GSA management.
No material acquisition or divestments.
Assessed Score: 10/20
Cost management effective. Continuous improvement
of risk management, processes and management
systems. Ongoing high level of stakeholder
engagement. Assessed Score: 15/20
4.6.3 STIP performance outcomes – Individual Results
Short Term Incentive (STI) for the year ended 30 June 2020
STI target
% of Fixed Annual
Remuneration
STI maximum
% of Fixed Annual
Remuneration
Cash STI
$
% earned of
maximum STI
opportunity
% forfeited of
maximum STI
opportunity
Executive KMP
Mr D. Maxwell
Mr A. Thomas
Ms V. Suttell
Ms A. Jalleh¹
Mr I. MacDougall
Mr E. Glavas
Mr M. Jacobsen
Former Executive KMP
Mr D. Clegg²
50%
25%
25%
25%
25%
25%
25%
25%
100%
50%
50%
50%
50%
50%
50%
439,200
108,570
110,880
87,210
98,325
98,175
102,293
48.00%
46.20%
46.20%
46.20%
42.75%
46.20%
44.48%
52.00%
53.80%
53.80%
53.80%
57.25%
53.80%
55.52%
50%
43,009
42.75%
57.25%
1. Ms Jalleh commenced as an Executive KMP on 9 August 2019.
2. Mr Clegg ceased as a member of the Executive Leadership Team on 31 December 2019.
62
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.6 2020 Executive KMP Performance and Remuneration Outcomes continued
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 2019.
The base for the graph is December 2016, 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 the Then Applicable Peer Group
– 8 December 2016 to 7 December 2019
-150%
-100%
-50%
0%
50%
100%
150%
200%
250%
Cooper Energy Limited
83%
35%
148%
73%
3%
41%
-8%
208%
213%
230%
-59%
-100%
The value of LTI that vested in December 2019 decreased compared to December 2018. The award which vested during the 2020 financial year
contained fewer rights than the previous award which vested in December 2018. The vesting of this award was also 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 2016 to 8 December 2019, Cooper Energy’s total shareholder return was 83% and
it achieved a Relative Total Shareholder Return percentile rank of 60%. This resulted in a vesting outcome of 47% of all performance rights and
SARs that were granted in December 2016.
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.
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.
63
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.8 2020 Remuneration Outcomes for Executive KMP
4.8.1 Remuneration realised by Executive KMP in 2020 and 2019 (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. This is the STIP awarded for performance over the 2018 and 2019 performance period
i.e. the STIP paid in 2020 related to performance over the 2019 financial year and the STIP paid in 2019 related to performance over the
2018 financial year;
• LTIP realised based on the market value of PRs and SARs that vested in December 2018 & 2019 (granted in December 2015 & 2016
respectively); and
• “Other” is the value of benefits including fringe benefits tax on accommodation, car parking and other benefits.
Executive KMP
Year
Fixed
Remuneration1
$
Mr D. Maxwell
Mr A. Thomas
Ms V. Suttell
Ms A. Jalleh²
Mr I. MacDougall
Mr E. Glavas
Mr M. Jacobsen
Former Executive KMP
Ms A. Evans3
Mr D. Clegg4
2020
2019
2020
2019
2020
2019
2020
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
905,247
845,000
463,250
437,250
472,500
435,520
347,532
453,750
415,933
417,500
390,000
453,750
401,342
117,370
351,000
257,045
524,018
STIP1
$
614,363
646,000
148,793
152,880
161,743
166,306
-
131,075
145,635
132,671
141,703
121,721
164,535
114,471
127,533
155,587
182,000
LTIP1
$
801,800
2,476,215
286,646
885,256
-
-
-
274,891
848,953
204,299
630,939
-
-
144,100
425,971
-
-
Other
$
74,755
80,904
6,515
5,916
6,515
5,916
35,535
6,515
5,916
6,515
5916
536
536
4,384
5,916
268
536
Total
$
2,396,165
4,048,119
905,204
1,481,302
640,758
607,742
383,067
866,231
1,416,437
760,985
1,168,558
576,007
566,413
380,325
910,420
412,900
706,554
1. Amounts above include adjustments for unpaid leave where applicable. Disclosure of realised LTIP in 2019 was the accounting fair value of
rights that vested during the period. Comparatives have been revised to reflect the market value of the vested shares at the time of issue.
2. Ms Jalleh commenced as an Executive KMP on 9 August 2019 and her entitlements are prorated.
3. Ms Evans worked part time and ceased as an Executive KMP on 9 August 2019 (0.9 full time equivalent to 28 June 2019, and 0.4 full time
equivalent to 20 December 2019). Her FY20 entitlements are prorated.
4. Mr Clegg ceased to be a member of the Executive Leadership Team and as an Executive KMP on 31 December 2019.
64
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.8 2020 Remuneration Outcomes for Executive KMP continued
4.8.2 Table of Executive KMP Statutory Remuneration Disclosure for 2020 and 2019 financial years
Short-term
Base Salary
STIP (a)
Benefits
Other
Short-term
Benefits(b)
Long-
term
Long
Service
Leave
Post
Employment(c)
Share Based
Remuneration(e)
Superannuation(d)
LTIP
Total
Executive KMP
Mr D. Maxwell
Mr A. Thomas
Ms V. Suttell
Ms A. Jalleh(f)
Mr I. MacDougall
$
$
$
$
2020
884,245
510,298
74,755
17,601
2019
2020
2019
2020
2019
2020
2020
2019
824,469
622,946
80,904
34,796
442,247
123,270
6,515
16,993
416,719
145,374
5,916
16,358
451,497
136,412
6,515
35,691
414,989
164,023
5,916
328,279
87,210
35,535
-
-
432,747
97,729
6,515
10,572
395,402
135,829
5,916
14,303
Mr E. Glavas
2020
396,497
111,282
6,515
5,257
2019
369,469
134,847
5,916
13,548
Mr M. Jacobsen
2020
432,747
92,343
2019
380,811
154,729
536
536
17,017
13,730
Former Executive KMP
Ms A. Evans(g)
2020
2019
107,923
6,864
4,384
(55,618)
330,469
121,362
5,916
12,472
Mr D. Clegg(h)
2020
246,544
39,682
2019
503,487
172,380
268
536
-
-
$
21,003
20,531
21,003
20,531
21,003
20,531
19,252
21,003
20,531
21,003
20,531
21,003
20,531
9,446
20,531
10,501
20,531
$
$
762,633
2,270,535
739,175
2,322,821
258,707
868,735
249,745
854,643
219,540
870,658
133,503
738,962
41,231
511,507
254,572
823,138
244,208
816,189
224,387
764,941
202,241
746,552
216,800
780,446
134,073
704,410
154,624
227,623
166,114
656,864
99,576
396,571
160,349
857,283
a) The STIP values noted for 2020 and 2019 include an under/over accrual representing the delta between the prior period accrual and what
was actually paid in respect of that year. This variance will not exist in future periods. Refer to 4.6.3 for STIP amount earnt in FY20 which will
be paid in FY21.
b) Other short-term benefits include fringe benefits on accommodation, car parking and other benefits.
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 4.11 above 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 are prorated.
g) Ms Evans worked part time and ceased as an Executive KMP on 9 August 2019 (0.9 full time equivalent to 28 June 2019, and 0.4 full
time equivalent to 20 December 2019). Her FY20 entitlements are prorated. The negative value for long service leave is as a result of the
unwinding of the accrual on cessation of employment.
h) Mr Clegg ceased to be a member of the Executive Leadership Team and as an Executive KMP on 31 December 2019.
65
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.8 2020 Remuneration Outcomes for Executive KMP continued
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
2019. 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)
Share Appreciation Rights (Equity Incentive Plan)
No. of rights
granted
during period
Fair value
of rights at
grant date
No. of
rights vested
during period
% of rights
vested to
30 June
2020
No. of rights
granted
during
period
Fair value
of rights at
grant date
No. of
rights vested
during period
% of rights
vested to
30 June
2020
Directors
Mr D. Maxwell
795,652
299,961
637,598
41%
2,779,465
439,155
1,666,575
41%
Executive KMP
Mr A. Thomas
286,086
107,854
227,943
42%
999,392
157,904
595,807
Ms V. Suttell
292,173
110,149
Ms A. Jalleh¹
228,260
86,054
-
-
Mr I. MacDougall
280,000
105,560
218,595
Mr E. Glavas
258,695
97,528
162,460
Mr M. Jacobsen
280,000
105,560
-
0%
0%
42%
38%
0%
1,020,656
161,264
797,387
125,987
-
-
978,128
154,544
571,373
903,705
142,785
424,643
978,128
154,544
-
Former
Executive KMP
Ms A. Evans²
-
-
114,935
38%
-
-
300,259
Mr D. Clegg³
328,695
123,918
-
0%
1,148,238
181,422
-
1. Ms Jalleh commenced as an Executive KMP on 9 August 2019.
2. Ms Evans ceased as an Executive KMP on 9 August 2019.
3. Mr Clegg ceased as a member of the Executive Leadership Team and as an Executive KMP on 31 December 2019.
42%
0%
0%
42%
38%
0%
40%
0%
The vesting date of the PRs granted on 11 December 2019 is 10 December 2022. The fair value of these rights is $0.38 per right and the share
price on grant date was $0.575. The performance period for these PRs commenced on 11 December 2019.
The vesting date of the SARs granted on 11 December 2019 is 10 December 2022. The fair value of these rights is $0.158 per right and the share
price on grant date was $0.575. The performance period for these SARs commenced on 11 December 2019.
66
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.8 2020 Remuneration Outcomes for Executive KMP continued
4.8.4 Movement in Performance Rights (PRs)
The movement during the reporting period in the number of PRs granted but not exercisable over ordinary shares in Cooper Energy held,
directly, indirectly or beneficially, by each KMP, including their related parties, is as follows:
Performance Rights
(Equity Incentive Plan)
Held at
1 July 2019
Granted
Lapsed
Vested &
Exercised
Held at
30 June 2020
Directors
Mr D. Maxwell1
Mr H. Gordon2
Executive KMP
Mr A. Thomas
Ms V. Suttell
Ms A. Jalleh³
Mr I. MacDougall
Mr E. Glavas
Mr M. Jacobsen
Former Executive KMP
Ms A. Evans⁴
Mr D. Clegg⁵
3,831,347
365,449
1,289,106
831,739
-
1,264,490
1,069,364
832,131
901,324
996,103
795,652
-
286,086
292,173
228,260
280,000
258,695
280,000
-
328,695
-
-
-
-
-
-
-
-
-
-
637,598
184,766
227,943
-
-
218,595
162,460
-
114,935
-
3,989,401
180,683
1,347,249
1,123,912
228,260
1,325,895
1,165,599
1,112,131
786,389
1,324,798
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. Ms Jalleh commenced as an Executive KMP on 9 August 2019.
4. Ms Evans ceased as an Executive KMP on 9 August 2019.
5. Mr Clegg ceased as a member of the Executive Leadership Team and as an Executive KMP on 31 December 2019.
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.
Share Appreciation Rights
(Equity Incentive Plan)⁶
Held at
1 July 2019
Granted
Lapsed
Vested &
Exercised⁶
Held at
30 June 2020
Directors
Mr D. Maxwell¹
Mr H. Gordon²
Executive KMP
Mr A. Thomas
Ms V. Suttell
Ms A. Jalleh³
Mr I. MacDougall
Mr E. Glavas
Mr M. Jacobsen
Former Executive KMP
Ms A. Evans⁴
Mr D. Clegg⁵
9,931,619
949,623
3,348,742
2,161,975
-
3,284,013
2,777,795
2,160,526
2,341,065
2,586,954
2,779,465
-
999,392
1,020,656
797,387
978,128
903,705
978,128
-
1,148,238
-
-
-
-
-
-
-
-
-
-
1,666,575
11,044,509
482,951
466,672
595,807
-
-
571,373
424,643
-
300,259
-
3,752,327
3,182,631
797,387
3,690,768
3,256,857
3,138,654
2,040,806
3,735,192
67
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.8 2020 Remuneration Outcomes for Executive KMP continued
4.8.4 Movement in Performance Rights (PRs) continued
The movement during the reporting period in the number of SARs granted held, directly, indirectly or beneficially, by each KMP, including their
related parties, is as follows:
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. Ms Jalleh commenced as an Executive KMP on 9 August 2019.
4. Ms Evans ceased as an Executive KMP on 9 August 2019.
5. Mr Clegg ceased as a member of the Executive Leadership Team and as an Executive KMP on 31 December 2019.
6. SARs represent the right to receive a quantity of shares based on an amount equal to the difference in share price at grant date and test date.
The 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 (note there is no proposed change in
Directors fees for 2021):
Chairman*
Member
Board
Audit
Committee
Risk &
Sustainability
Committee
People and
Remuneration
Committee
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.
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.
68
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report 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:
Held at
1 July 2019
Purchases
Directors
Mr J. Conde AO
Mr D. Maxwell
Ms E. Donaghey
Mr H. Gordon
Mr J. Schneider
Ms A. Williams
Ms V. Binns¹
Mr T. Bednall¹
Executive KMP
Mr A. Thomas
Ms V. Suttell
Ms A. Jalleh²
Mr I. MacDougall
Mr E. Glavas
Mr M. Jacobsen
Former Executive KMP
Ms A. Evans³
Mr D. Clegg⁴
859,093
17,416,881
160,000
2,673,781
1,016,594
179,444
-
44,499
4,328,970
40,600
-
2,677,157
1,712,405
-
1,821,381
135,000
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Received on
vesting of
PRs & SARs
-
1,457,484
-
422,357
-
-
521,055
-
-
499,687
371,367
-
262,114
-
Sales
Held at
30 June 2020
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
859,093
18,874,365
160,000
3,096,138
1,016,594
179,444
-
44,499
4,850,025
40,600
-
3,176,844
2,083,772
-
2,083,495
135,000
1. Ms Binns and Mr Bednall were appointed to a casual vacancy as Non-Executive Directors during the reporting period. Their appointments are
to be confirmed by shareholders at the 2020 annual general meeting scheduled for 12 November 2020. Mr Bednall held these shares at the
time of his appointment as a Non-Executive Director (casual vacancy).
2. Ms Jalleh commenced as an Executive KMP on 9 August 2019.
3. Ms Evans ceased as an Executive KMP on 9 August 2019.
4. Mr Clegg ceased as a member of the Executive Leadership Team on 31 December 2019.
Options
No options were issued (or forfeited) during the year.
69
Director’s Statutory Report
For the year ended 30 June 2020
4. Remuneration Report continued
4.9.3 Table of Directors’ remuneration for 2020 and 2019 financial years
Short-term
Base Salary
STIP(a)
Benefits
Other
Short-term
Benefits(b)
$
219,178
191,781
$
-
-
$
-
-
Long
Term
Long
Service
Leave
$
-
-
884,245
510,298
74,755
17,601
824,469
622,946
80,904
34,796
137,131
91,324
136,225
118,722
136,986
118,722
40,335
30,863
136,225
118,722
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Executives
Mr J. Conde AO
Mr D. Maxwell
Ms E. Donaghey
Mr H. Gordon
Mr J. Schneider
Ms V. Binns(e)
Mr T. Bednall(e)
Ms A. Williams
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2020
2020
2019
Post
Employment
Share Based
Remuneration(d)
Superannuation(c)
LTIP
Total
$
20,822
18,219
21,003
20,531
13,027
8,875
12,941
11,278
13,014
11,279
3,832
2,932
12,941
11,279
$
-
-
$
240,000
210,000
762,633
2,270,535
739,175
2,322,821
-
-
150,158
100,199
31,926
181,092
93,091
223,091
-
-
-
-
-
-
150,000
130,001
44,167
33,795
149,166
130,001
a) The STIP values noted for 2020 and 2019 include an under/over accrual representing the delta between the prior period accrual and what
was actually paid in respect of that year. This variance will not exist in future periods. Refer to 4.6.3 for STIP amount earnt in FY20 which will
be paid in FY21.
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 4.7.1 above and in more
detail in Note 27 of the Notes to the Financial Statements. PRs and SARs were granted to Mr Gordon when he was an Executive Director.
e) Ms Binns and Mr Bednall were appointed to a casual vacancy as Non-Executive Directors on the dates above. Their appointments are to be
confirmed by shareholders at the 2020 annual general meeting scheduled for 12 November 2020.
End of remuneration report.
70
Director’s Statutory Report
For the year ended 30 June 2020
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 Shares
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. Williams
859,093
18,874,365
44,499
Nil
160,000
3,096,138
1,016,594
179,444
Nil
3,989,401
Nil
Nil
Nil
180,683
Nil
Nil
Nil
11,044,509
Nil
Nil
Nil
466,672
Nil
Nil
11. Share options and rights
At the date of this report, there are no unissued ordinary shares of the parent entity under option.
At the date of this report, there are 17,862,629 outstanding PRs and 48,280,025 SARs under the Equity Incentive Plan approved by shareholders
at the 2019 AGM.
During the financial year 5,096,588 shares were issued as a result of PRs exercised. At the date of this report, no PRs have vested and been
exercised subsequent to 30 June 2020.
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.
71
Director’s Statutory Report
For the year ended 30 June 2020
14. Indemnification and insurance of directors and officers
14.1 Indemnification
The parent entity has agreed to indemnify the current Directors and past Directors of the parent entity and of the subsidiaries, where applicable,
against all liabilities (subject to certain limited exclusions) to persons (other than the Group or a related body corporate) which arise out of
the performance of their normal duties as a Director or Executive Director unless the liability relates to conduct involving a lack of good faith.
The parent entity has agreed to indemnify the Directors and Executive Directors against all costs and expenses incurred in defending an action
that falls within the scope of the indemnity and any resulting payments.
14.2 Insurance premiums
During the financial year, the parent entity has paid insurance premiums in respect of Directors’ and Officers’ liability and legal insurance
contracts for current and former Directors and Officers including senior employees of the Parent entity. The insurance premium relates to
costs and expenses incurred by the relevant officers in defending proceedings, whether civil or criminal and whatever their outcome and other
liabilities that may arise from their position, with the exception of conduct involving a wilful breach of duty or improper use of information or
position to gain a personal advantage. The insurance policy outlined above does not contain details of premiums paid in respect of individual
Directors, Officers and senior employees of the parent entity.
15. Indemnification of auditors
To the extent permitted by law, the Company has agreed to indemnify its auditors, Ernst & Young, as part of the terms of its audit engagement
agreement against claims by third parties arising from the audit (for an unspecified amount) except in the case where the claim arises because
of Ernst & Young’s negligent, wrongful or wilful acts or omissions. No payment has been made to indemnify Ernst & Young during or since the
financial year.
16. Auditor’s independence declaration
The auditor’s independence declaration is set out on page 126 and forms part of the Directors’ report for the financial year ended 30 June 2020.
17. Non-audit services
The amounts paid and payable to the auditor of the Group, Ernst & Young and its related practices for non-audit services provided during the
year was $187,915 (2019: $193,650). The directors are satisfied that the provision of non-audit services is compatible with the general standard of
independence for auditors imposed by the Corporations Act 2001. The nature and scope of each type of non-audit service provided means that
auditor independence was not compromised.
18. Rounding
The Group is of a kind referred to in ASIC Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191 dated 24 March 2016
and in accordance with that Legislative Instrument, amounts in the financial report have been rounded to the nearest thousand dollars, unless
otherwise stated.
This report is made in accordance with a resolution of the Directors.
Mr John C. Conde AO
Chairman
Mr David P. Maxwell
Managing Director
Dated at Adelaide 31 August 2020
72
Cooper Energy Limited and its controlled entities
Financial Statements
For the year ended 30 June 2020
73
Consolidated Statement of Comprehensive Income
For the year ended 30 June 2020
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
Loss after tax for the period attributable to shareholders
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)/earnings per share
Diluted (loss)/earnings per share
Notes
2
2
2
2
19
19
3
3
22
22
22
20
4
4
2020
$’000
78,139
(54,520)
23,619
2019
$’000
75,543
(43,570)
31,973
19,828
796
(147,546)
(44,422)
1,728
(7,587)
3,398
(4,972)
(109,958)
(13,227)
25,575
(1,646)
23,929
10,040
(8,864)
1,176
(86,029)
(12,051)
(1,173)
2,140
(383)
-
(1,277)
383
(690)
(106)
(989)
(1,883)
(86,135)
(13,934)
Cents
(5.3)
(5.3)
Cents
(0.7)
(0.7)
The above Consolidated Statement of Comprehensive Income should be read in conjunction with the accompanying notes.
74
Consolidated Statement of Financial Position
As at 30 June 2020
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
Total Assets
Liabilities
Current Liabilities
Trade and other payables
Provisions
Lease liabilities
Other financial liabilities
Interest bearing loans and borrowings
Total Current Liabilities
Non-Current Liabilities
Provisions
Lease liabilities
Government grants
Interest bearing loans and borrowings
Other financial liabilities
Deferred Petroleum Resource Rent Tax Liability
Total Non-Current Liabilities
Total Liabilities
Net Assets
Equity
Contributed equity
Reserves
Accumulated losses
Total Equity
Notes
2020
$’000
2019
$’000
5
6
7
8
21
10
11
16
12
13
3
9
15
16
21
18
15
16
17
18
21
3
20
20
20
131,583
19,996
6,106
822
164,289
21,169
3,346
426
158,507
189,230
21,532
16,366
1,878
9,738
159,078
615,980
46,836
871,408
21,740
4,580
36
-
152,268
613,198
20,757
812,579
1,029,915
1,001,809
21,183
19,902
1,045
-
26,000
68,130
374,671
12,004
-
203,438
3,642
16,948
610,703
44,533
11,131
-
1,758
-
57,422
276,789
-
430
213,680
3,482
16,293
510,674
678,833
568,096
351,082
433,713
475,862
11,180
(135,960)
351,082
474,397
9,247
(49,931)
433,713
The above Consolidated Statement of Financial Position should be read in conjunction with the accompanying notes.
75
Consolidated Statement of Changes in Equity
For the year ended 30 June 2020
Balance at 1 July 2019
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 2020
Balance at 1 July 2018
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
Shares issued
Balance as at 30 June 2019
Notes
Issued
Capital
$’000
Reserves
Accumulated
Losses
$’000
$’000
Total
Equity
$’000
474,397
9,247
(49,931)
433,713
-
-
-
-
1,465
-
(86,029)
(86,029)
(106)
(106)
-
(106)
(86,029)
(86,135)
3,504
(1,465)
-
-
3,504
-
475,862
11,180
(135,960)
351,082
471,837
-
-
-
-
2,217
343
474,397
9,925
-
(1,883)
(1,883)
3,422
(2,217)
-
9,247
(37,880)
(12,051)
-
(12,051)
443,882
(12,051)
(1,883)
(13,934)
-
-
-
3,422
-
343
(49,931)
433,713
20
20
20
20
20
The above Consolidated Statement of Changes in Equity should be read in conjunction with the accompanying notes.
76
Consolidated Statement of Cash Flows
For the year ended 30 June 2020
Cash Flows from Operating Activities
Receipts from customers
Payments to suppliers and employees
Payments of exit provision
Payments for restoration
Petroleum Resource Rent Tax refund/(paid)
Interest received
Interest paid
Net cash from operating activities
Cash Flows from Investing Activities
Transfers to term deposits
Transfers from/(to) escrow proceeds receivable
Payments for property, plant and equipment
Payments for intangibles
Receipts of consideration receivable
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
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
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)
-
2019
$’000
79,873
(44,510)
(3,133)
(14,348)
(530)
3,152
-
20,504
16
20,571
(2,571)
(36)
894
(35,057)
(11,962)
(38,703)
(180,010)
(9,665)
(11,015)
(91,390)
(184,113)
(698)
11,284
(257)
10,329
-
92,290
(1,559)
90,731
(32,999)
(72,878)
293
164,289
131,583
260
236,907
164,289
77
Notes to the Consolidated Financial Statements
For the year ended 30 June 2020
Corporate information
The consolidated financial report of Cooper Energy Limited and its controlled entities (“Cooper Energy” or “the Group”) for the year ended
30 June 2020 was authorised for issue in accordance with a resolution of the Directors on 31 August 2020. Cooper Energy Limited is a for profit
company limited by shares incorporated and domiciled in Australia whose shares are publicly traded on the Australian Securities Exchange.
The nature of the operations and principal activities of the Group are described in the Directors’ Statutory Report and Note 1.
Basis of preparation
The financial report is a general-purpose financial report, which has been prepared in accordance with the requirements of the Corporations
Act 2001, Australian Accounting Standards and other authoritative pronouncements of the Australian Accounting Standards Board (AASB) and
International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).
The financial report has also been prepared on a historical cost basis, except for equity instruments measured at fair value through other
comprehensive income and derivative financial instruments measured at fair value through profit and loss.
The financial report is presented in Australian dollars and under the option available to the Group under ASIC Corporations (Rounding in
Financial/Directors’ Reports) Instrument 2016/191, all values are rounded to the nearest thousand dollars ($’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. Price assumptions for oil and uncontracted gas have been revised to
reflect the lower, post-COVID-19 prices, resulting in impairment recognised by the Group. Beyond the impact of the oil and gas prices, there
has not been a significant impact on the operations of the Group. 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
In the process of applying the Group’s accounting policies, management is required to make judgements, estimates and assumptions that affect
the reported amounts in the financial statements. Judgements, estimates and assumptions which are material to specific notes of the financial
statements are below:
Note 3
Income tax
Note 15
Provisions
Note 27
Share based payments
Note 13
Oil and gas assets
Note 16
Leases
Note 14
Impairment
Note 23
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.
78
Notes to the Consolidated Financial Statements
For the year ended 30 June 2020
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
The Sole Gas Project involved development of the Sole gas field by Cooper Energy and upgrading of the Orbost Gas Processing Plant (OGPP) to
process Sole gas by the APA Group. Commissioning of the plant upgrade is yet to meet the performance standards for completion, which
include demonstrated capacity to supply 68 TJ/day of Sole gas into the Eastern Gas Pipeline.
Foaming in the absorber section of the plant has impaired output rates from the OGPP and been accompanied by fouling which required two
shutdowns for maintenance prior to 30 June. The shutdowns and optimisation of operations by APA have resulted in improved plant
performance but have not been sufficient for the plant to reach the required demonstrated capacity to achieve Practical Completion.
APA and Cooper Energy are working collaboratively to improve plant performance to that required for the completion of commissioning.
Subsequent to year-end the two companies announced a Transition Agreement (TA) which establishes the commercial framework for this
collaboration and progress towards the commencement of firm gas supply and the practical completion of the OGPP. Under the agreement
revenue and operating and capital costs will be shared while the OGPP proceeds to Practical Completion.
Root cause analysis to identify the cause of the foaming, has been ongoing with involvement of the OGPP technology provider. APA has
conducted minor plant modifications to improve performance, with further modifications planned for completion in September 2020. Planning
is also underway for Phase 2 works to increase gas processing capacity, which will include the flexibility to reconfigure the two absorber vessels
from a sequential to a parallel arrangement. The uncertainties associated with the progress to Practical Completion of the OGPP have required
management to make significant accounting judgments and estimates. These are set out below.
Progress of the OGPP and the Sole Gas project to Practical Completion
The Phase 2 works (scope currently being finalised and subject to approval) are currently planned to commence in the December quarter
(timing subject to supply chain and COVID-19 restrictions) for the resumption of production in the latter half of that quarter. The cost of the
Phase 2 works has not been finalised, with current estimates being $15 million (Cooper Energy share $7.5 million).
Commencement of term gas supply contracts from Sole has been deferred until the earlier of January 2021 or when permitted by the
commencement of firm supply from the OGPP. Whilst OGPP has demonstrated capability to maintain stable supply of 40-45 TJ/day,
Cooper Energy and APA are working to establish firm supply capability from the plant in advance of Practical Completion.
The uncertainties associated with near term sales volumes, the extent to which those volumes will be sold at spot market prices versus GSA
prices, costs of Phase 2 works, and timing of Practical Completion are all estimates which impact on the financial outcomes of the project. This
has been considered in the impairment assessment performed for the Sole CGU. Further details are set out in Note 14. The progress towards
Practical Completion also impacts on the accounting for the OGPP arrangement, including when the lease will be considered to commence.
Further details, including the judgments involved, are set out in the New accounting standard and interpretation section that follows.
Impacts on funding, liquidity and going concern:
Cooper Energy’s development of the Sole gas field was funded through the Company’s Reserve Based Lending facility (RBL). The RBL was
established principally to fund the Sole Gas Project capital expenditures and is secured against Group Borrowing Based Assets. A requirement
under the RBL was for project completion to occur by 31 July 2020 with a long-stop date of 31 August 2020. Prior to 30 June 2020, the lending
syndicate agreed to review and reset these dates once appropriate information has been made available pertaining to the additional technical
works required to reach full processing capacity levels. All covenant requirements, which comprise primarily of information requests under the
current terms, were met at 30 June 2020, or waived prior to that date. Accordingly, at 30 June 2020, amounts drawn under the RBL facility have
been classified as current or non-current according to the repayment profile expected to apply under the terms of the Syndicated Facility
Agreement (SFA) following completion of the Sole Gas Project. Refer Note 18.
As at the date of the report, the Group has met and continues to meet all the requirements under the RBL. As noted, the lending syndicate has
agreed to review and reset dates for Practical Completion once further information is made available. The lending syndicate has agreed to the
provision of information requested in the fourth quarter of calendar 2020, when they will assess the information provided. The revised plan
requires approval from Lenders. Failure to provide the information requested by Lenders within agreed timeframes, or failure to agree the
technical plan and revised date for Project Completion is a review event under the SFA.
The directors believe the Company will be able to provide the required information within agreed timeframes and reach agreement on the path
to achieve project completion. This view has been made on the basis of technical work already progressed alongside APA as operator of the
OGPP, commercial arrangements under a TA entered into with APA in August 2020 to facilitate full processing capacity levels, and the
discussions with and continuing support from the Company’s lenders and gas customers.
The Group holds significant cash balances of $131.6 million as at the end of the reporting period and has drawn debt of $229.4 million at that
date. Cash flow forecasts for the Group, inclusive of the impact of the TA and under various 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 that will be required post Practical Completion as
the RBL was designed to allow for a reset or redetermination at that time. Under the reasonably possible scenarios modelled, the Group
maintains at all times the liquidity levels required under the RBL facility.
Throughout commissioning of the OGPP, Cooper Energy has ensured the lending syndicate has been kept fully apprised of the commissioning
status of the OGPP. While the facility does allow for a Review Event under certain circumstances, the mechanisms in the SFA requires Lenders to
negotiate in good faith to agree outcomes under the existing structure of the RBL facility. The directors consider that if a Review Event is called,
the possibility of an Event of Default occurring due to an inability of Cooper Energy and the Lenders to agree the relevant matters is remote.
The syndicate holds security over the company’s 2P Reserves and Gas Sales Agreements with customers for offtake from Sole. In parallel to
other workstreams, Cooper Energy has worked with customers to defer commencement of Gas Sales Agreements and is currently providing
available volumes to customers at spot gas prices. It is the view of the directors based on current indications and advice that the lending
syndicate will continue to support Cooper Energy and the Sole Gas Project, including the likely agreement of amendments to the RBL, as
anticipated through the mechanisms in the SFA, once a technical plan is finalised and approved by APA and Cooper Energy.
79
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 2020 financial year.
The Group has adopted AASB 16 Leases (AASB 16) and AASB Interpretation 23 Uncertainty Over Income Tax Treatments, issued by the Australian
Accounting Standards Board (the AASB) that are relevant to its operations and effective for the current year.
AASB 16 Leases
The Group adopted AASB 16 from 1 July 2019. AASB 16 introduced a single, on-balance sheet accounting model for leases, which replaced AASB
117 Leases, AASB Interpretation 4 Determining Whether an Arrangement contains a Lease, AASB Interpretation 127 Evaluation of the Substance
of Transactions Involving the Legal Form of a Lease and AASB Interpretation 115 Operating Leases – Incentives. Before the adoption of AASB 16,
the Group classified each of its leases (as lessee) at the inception date as either a finance lease or an operating lease depending on whether risks
and rewards incidental to ownership of the leased asset transferred to the Group. Under this approach only finance leases were recognised on
the balance sheet from the lease commencement date. Upon adoption of AASB 16, the Group applied a single on-balance sheet recognition and
measurement approach for all leases for which it is the lessee. The Group has also elected to use the recognition exemptions for lease contracts
that, at the commencement date, have a lease term of 12 months or less and do not contain a purchase option (‘short-term leases’), and lease
contracts for which the underlying asset is of low value (‘low-value assets’).
In accordance with the transition provisions of AASB 16, the Group has adopted the modified retrospective method, measuring the right of
use asset as equal to the lease liability, with the cumulative effect of adopting AASB 16 recognised as an adjustment to the opening balance of
retained earnings at 1 July 2019, with no restatement of comparative information. This resulted in the Group recognising its property leases on
balance sheet, finance costs in relation to the lease and depreciation of the right-of-use asset. These property leases were previously recognised
as a lease expense in the Consolidated Statement of Comprehensive Income.
The Group will recognise a depreciation expense and interest expense from the date the underlying asset is available for use.
Transition impact
At transition, the Group recognised a right-of-use asset representing its right to use the underlying asset and lease liabilities for all leases with a
term of more than 12 months, excluding low-value leases. The group elected to apply the following available transition practical expedients:
• Applied a single discount rate to a portfolio of leases with similar characteristics. The portfolio of leases is grouped based on similar remaining
lease terms, similar class of underlying asset and similar economic environment.
• Applied the short-term lease exemption to leases with a lease term that ends within 12 months at the date of initial recognition
• Applied the exemption for leases of low-value assets.
As a result, as at 1 July 2019, the following were the impacts of the transition:
Assets: Right-of-use assets
Liabilities: Trade and other payables
Liabilities: Lease liabilities
1 July 2019
$’000
8,135
1,243
(9,378)
The table below reconciles the operating lease commitments as at 30 June 2019 to the lease liabilities as at 1 July 2019. There was no impact on
opening retained earnings.
Operating lease commitments as at 30 June 2019
Weighted average incremental borrowing rate as at 1 July 2019
Discounted operating lease commitments at 1 July 2019
Add
Payments in optional extension periods not recognised as at 30 June 2019
Lease liabilities as at 1 July 2019
There is no material impact on other comprehensive income and the basic and diluted EPS.
80
$’000
9,346
4.925%
5,240
4,138
9,378
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 New accounting standards and interpretations continued
Orbost Gas Processing Plant
Under AASB 16, the Group will recognise a right-of-use asset and corresponding lease liability in relation to the Orbost Gas Processing Plant
(OGPP). The Sole Gas Processing Agreement creates a right-of-use asset and will be recognised at an amount equal to the corresponding lease
liability. The Group will recognise a right-of-use asset and lease liability under AASB 16 for the Orbost Gas Processing Plant at the date the
underlying asset is available for use. The Group currently expects the agreement, which was signed prior to 1 July 2019, to result in a right-
of-use asset and lease liability of approximately $280 million to $310 million based on current information, with recognition to occur in the
second half of the 2021 financial year once the asset is available for use. 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. This does
not contemplate any payments associated with processing gas through the OGPP under the transition agreement entered into with APA on
20 August 2020.
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 Orbost
Gas Processing Plant 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.
AASB Interpretation 23 - Uncertainty Over Income Tax Treatments
The Group has applied AASB Interpretation 23 from 1 July 2019. The recognition, measurement and disclosure requirements of the standard have
been applied to any uncertain tax treatments. The Group has determined it is probable that the current estimated treatment will be accepted by
the Australian Taxation Office and the tax provision calculation is in line with tax filings.
Notes to the financial statements
The notes include information which is required to understand the financial statements and is material and relevant to the operations, financial
position and performance of the Group. They include applicable accounting policies applied and significant judgements, estimates and
assumptions made. Specific accounting policies are disclosed in the respective notes to the financial statements.
The notes are organised into the following sections:
Group performance
Working capital
Capital employed
Funding and risk management
Group structure
Other information
Provides additional information regarding financial statement lines that are most relevant to
explaining the Group’s performance during the period.
Provides additional information regarding financial statement lines that are most relevant to
explaining the assets used to generate the Group’s trading performance during the period.
Provides additional information regarding financial statement lines that are most relevant to
explaining the capital investments made that allows the Group to generate its operating result
during the period and liabilities incurred as a result.
Provides additional information regarding financial statement lines that are most relevant to
explaining the Group’s funding sources. This section also provides information relating to the
Group’s exposure to various financial risks, its impact on the financial position and performance of
the Group and how these risks are managed.
Summarises how the group structure affects the financial position and performance of the Group as
a whole.
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.
81
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 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 Lattice Energy Limited.
South-East Australia
The South-East Australia segment primarily consists of the Sole Gas Project, Manta Gas Project and the Group’s interest in the operated Casino
Henry and non-operated Minerva producing gas assets. 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.
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.
Segments
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)/income
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
Right-of-use assets
Cooper
Basin
$’000
14,558
14,558
6,486
(3,573)
(7,836)
(95)
(5,018)
-
-
(5,018)
14,969
8,731
6,802
5,579
-
-
-
South-East
Australia
Corporate
and Other
Consolidated
(restated)
$’000
$’000
$’000
63,581
63,581
42,937
(23,234)
(99,662)
(3,943)
(83,902)
-
(1,646)
(85,548)
802,263
421,656
85,651
48,610
11,593
-
-
-
-
(17,094)
(2,123)
-
(1,821)
(21,038)
-
-
(21,038)
212,683
248,446
-
-
1,481
2,017
2,723
6,266
78,139
78,139
32,329
(28,930)
(107,498)
(5,859)
(109,958)
25,575
(1,646)
(86,029)
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
145,809
82
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020
1. Segment reporting continued
Accounting policies and inter-segment transactions continued
Segments
30 June 2019
Revenue from oil and gas sales to external customers
Total revenue
Segment result before interest, tax, depreciation,
amortisation and impairment
Depreciation and amortisation
Net finance (costs)/income
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
Cooper
Basin
$’000
South-East
Australia
Corporate
and Other
Consolidated
(restated)
$’000
$’000
$’000
23,283
23,283
14,168
(1,628)
(101)
12,439
-
-
12,439
19,059
6,719
2,015
1,831
-
-
52,260
52,260
7,126
(16,713)
(4,871)
(14,458)
-
(8,864)
(23,322)
765,765
342,798
52,881
234,914
184
-
-
-
(13,778)
(828)
3,398
(11,208)
-
-
(11,208)
216,985
218,579
-
-
2,579
36
2,615
75,543
75,543
7,516
(19,169)
(1,574)
(13,227)
10,040
(8,864)
(12,051)
1,001,809
568,096
54,896
236,745
2,763
36
294,440
Total additions of non-current assets
3,846
287,979
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. In 2019, revenue from two customers amounted to $42.2 million, and
$5.4 million respectively in the South-East Australia segment and $22.7 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
Fair value movement on commodity price options
Total other revenue
Total revenue from oil and gas sales
Notes
2020
$’000
2019
$’000
15,563
63,581
79,144
(1,005)
-
(1,005)
78,139
23,744
52,260
76,004
(445)
(16)
(461)
75,543
83
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020
2020
$’000
19,800
28
-
-
19,828
(26,511)
(1,203)
(26,452)
(354)
(54,520)
(693)
(15,123)
(828)
(176)
(1,120)
(3,597)
(14,056)
(3,100)
2019
$’000
-
-
774
22
796
(23,327)
(1,902)
(18,179)
(162)
(43,570)
(762)
(11,933)
(828)
-
-
(590)
(26,205)
(1,360)
-
(358)
236
1,623
(4,245)
(44,422)
(17,002)
(3,422)
(853)
(21,277)
14
(107,498)
(123)
-
119
(1,351)
(147,546)
(20,412)
(3,504)
(1,264)
(25,180)
-
(951)
2. Revenues and expenses continued
Notes
Other income
Liquidated damages¹
Other
Gain on exit provision
Gain on movement of consideration receivable
Total other income
Cost of sales
Production expenses²
Royalties
Amortisation of oil and gas assets
Depreciation of property, plant and equipment
Total cost of sales
Other expenses
Selling expense²
General administration²
Depreciation of property, plant and equipment
Amortisation of intangibles
Depreciation of right-of-use assets
Care and maintenance
Restoration expense
Exploration and evaluation expense
Impairment expense
Fair value adjustment of success fee liability
Fair value movement on oil price derivatives
Realised and unrealised foreign currency translation (loss)/gain
Other (including new ventures)²
Total other expenses
Employee benefits expense included in general administration
Director and employee benefits
Share based payments
Superannuation expense
Total employee benefits expense (gross)
Lease payments included in general administration
Minimum lease payment – operating lease (gross)
1. Liquidated damages received from APA in relation to the Sole delay
2. Comparatives have been restated for reclassification between expense categories
84
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 2. Revenues and expenses continued
Accounting Policy
Revenue from contracts with customers
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
Over provision in respect of prior year income tax
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/(expense)
2020
$’000
2019
$’000
(504)
(504)
26,070
9
26,079
25,575
(5,686)
3,299
(2,387)
741
741
(1,646)
23,929
-
-
7,522
2,518
10,040
10,040
(3,760)
(492)
(4,252)
(4,612)
(4,612)
(8,864)
1,176
85
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 3. Income tax continued
Reconciliation between tax expense and pre-tax net profit
Accounting (loss)/profit before tax from continuing operations
Income tax using the domestic corporation tax rate of 30% (2019: 30%)
(Increase)/decrease in income tax expense due to:
Deductible expenditure
Non-assessable income
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/(expense)
Income tax recognised in other comprehensive income
Fair value movement on derivative financial instruments
Income tax using the domestic corporation tax rate of 30% (2019: 30%)
Tax Consolidation
2020
$’000
2019
$’000
(109,958)
32,987
(13,227)
3,968
-
-
(187)
9
197
(8,112)
681
25,575
(1,646)
23,929
-
-
161
232
(1,469)
2,518
1,383
-
3,247
10,040
(8,864)
1,176
383
383
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 2020, 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 (2019: $nil).
Franking Tax Credits
At 30 June 2020 the parent entity had franking tax credits of $42.9 million (2019: $42.9 million). The fully franked dividend equivalent is
$142.9 million (2019: $142.9 million).
Petroleum Resource Rent Tax (PRRT)
Cooper Energy Limited has recognised a Deferred Tax Liability for Petroleum Resource Rent Tax (PRRT) of $16.9 million (2019: $16.3 million)
relating to PRRT on the Group’s producing gas assets. The Group has not recognised a Deferred Tax Asset for PRRT of $29.0 million (2019:
$19.1 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. From 1 July 2019, there was a change in the PRRT legislation so that
onshore petroleum projects will no longer be subject to PRRT. The Group has significant levels of undeducted expenditure in respect of the
Cooper Basin oil producing assets that will not be utilised.
86
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 3. Income tax continued
Income Tax Losses
(a) Revenue Losses
A Deferred Tax Asset has been recognised for the year ended 30 June 2020 of $35.0 million (2019: $23.6 million).
(b) Capital Losses
Cooper Energy has not recognised a Deferred Tax Asset for Australian income tax capital losses of $15.5 million (2019: $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. Capital losses have
been utilised in the prior year to offset the capital gain generated from the sale of the Orbost Gas Processing Plant and the receipt of funds from
exited joint venture parties for the BMG abandonment.
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
Unrealised currency translation gain
Deferred tax assets
Leases
Provision for employee entitlements
Provisions
Other
Capital raising costs
Tax losses
Deferred tax benefit
Consolidated
Statement of Financial
Position
Consolidated Statement
of Comprehensive
Income
2020
$’000
2019
$’000
2020
$’000
2019
$’000
(62)
33,974
17,118
40
83
-
2,240
20,325
8,293
40
103
-
2,302
(13,649)
(8,825)
-
20
-
1,343
(4,172)
(4,211)
(40)
(62)
-
51,153
31,001
(20,152)
(7,142)
993
1,422
53,392
5,903
1,213
35,066
97,988
-
2,082
18,410
5,377
2,261
23,628
51,758
993
(660)
-
259
34,982
13,808
525
(1,048)
11,438
46,230
26,078
2,064
(965)
2,016
17,182
10,040
Deferred tax asset from corporate tax
46,836
20,757
Deferred income tax from PRRT
Deferred income tax at 30 June relates to:
Deferred tax liabilities
Oil and gas assets
Deferred tax (expense)
16,948
16,293
25
25
(4,612)
(4,612)
Deferred tax liability from PRRT
16,948
16,293
87
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 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.
88
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 4. Earnings per share
The following reflects the net (loss)/profit and share data used in the calculations of earnings per share:
Net (loss)/profit after tax attributable to shareholders
2020
$’000
2019
$’000
(86,029)
(12,051)
2020
Thousands
2019
Thousands
Weighted average number of ordinary shares used in calculating basic earnings per share
1,624,260
1,611,905
Dilutive performance rights and share appreciation rights1
-
-
Weighted average number of ordinary shares used in calculating dilutive earnings per share
1,624,260
1,611,905
Basic loss per share for the period (cents per share)
Diluted loss per share for the period (cents per share)
(5.3)
(5.3)
(0.7)
(0.7)
1. The weighted average number of potentially dilutive shares at 30 June 2020 is 12.4 million (2019: 24.6 million)
At 30 June 2020 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.
89
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 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 expense
Share based payments
Finance costs
Foreign exchange (gain)/loss
Other non-cash movements
2020
$’000
111,567
20,016
131,583
2019
$’000
136,539
27,750
164,289
2020
$’000
2019
$’000
(87,204)
(12,051)
26,452
1,182
176
1,120
107,498
3,100
14,056
3,504
4,038
(293)
1,804
18,179
990
-
-
-
1,360
26,205
3,422
4,972
(778)
(656)
Net cash from operating activities before changes in assets or liabilities
75,433
41,643
Add/(deduct) changes in operating assets or liabilities:
Decrease in trade and other receivables
(Increase)/decrease in inventories
Increase in prepayments
Decrease in deferred taxes
Increase/(decrease) in trade and other payables
Decrease in provisions
Net cash from operating activities
Reconciliation of liabilities arising from financing activities
Balance at beginning of period
Financing cash flows¹
Non-cash financing movements²
Balance at end of period
1,173
(396)
(3,760)
(25,424)
2,750
(1,714)
48,062
Borrowings
Lease Liabilities
2020
$’000
213,680
11,284
4,474
229,438
2019
$’000
116,923
92,290
4,467
213,680
2020
$’000
-
(698)
13,747
13,049
4,694
41
(560)
(4,486)
(7,169)
(13,659)
20,504
2019
$’000
-
-
-
-
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.
90
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 6. Trade and other receivables
Current Assets
Trade receivables
Accrued revenue
Interest receivable
2020
$’000
17,783
2,176
37
19,996
2019
$’000
9,474
11,349
346
21,169
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
2020
$’000
1,530
4,384
192
6,106
2020
$’000
822
2019
$’000
884
25
2,437
3,346
2019
$’000
426
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)
Deferred lease incentive
Accounting Policy
2020
$’000
14,844
6,339
-
21,183
2019
$’000
5,046
36,598
2,889
44,533
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.
91
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020
Capital Employed
10. Property, plant and equipment
Reconciliation of carrying amounts at
beginning and end of period:
Carrying amount at beginning of period
Assets acquired
Additions
Disposals/written off
Depreciation
Carrying amount at end of period
Cost
Accumulated depreciation
Carrying amount at end of period
Accounting Policy
Production assets
Corporate assets
Total
2020
$’000
2019
$’000
2020
$’000
543
8,674
2,813
-
(354)
11,676
15,567
(3,891)
11,676
521
-
184
-
(162)
543
4,080
(3,537)
543
4,037
-
1,481
-
(828)
4,690
7,556
(2,866)
4,690
2019
$’000
2,343
-
2,579
(57)
(828)
4,037
6,075
(2,038)
4,037
2020
$’000
4,580
8,674
4,294
-
(1,182)
16,366
23,123
(6,757)
16,366
2019
$’000
2,864
-
2,763
(57)
(990)
4,580
10,155
(5,575)
4,580
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 14 for impairment policy). Historical
cost includes expenditure that is directly attributable to the acquisition of the items. Subsequent costs are included in the asset’s carrying
amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item
will flow to the Group and the cost of the item can be measured reliably. Repairs and maintenance are recognised in the Consolidated
Statement of Comprehensive Income as incurred.
Depreciation on property plant and equipment is calculated at between 7.5% and 37.5% per annum using the diminishing value method
over the 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.
11. Intangible assets
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at beginning of period
Additions
Amortisation
Carrying amount at end of period
Cost
Accumulated depreciation
Carrying amount at end of period
Accounting Policy
2020
$’000
36
2,018
(176)
1,878
2,054
(176)
1,878
2019
$’000
-
36
-
36
36
-
36
Intangible assets comprises 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.
92
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020
12. 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
Carrying amount at end of period¹
Notes
14
2020
$’000
152,268
92,453
(3,100)
(79,398)
(3,145)
159,078
2019
$’000
98,732
54,896
(1,360)
-
-
152,268
1. Recoverability is dependent on the successful development and commercial exploration or sale of the respective areas of interest.
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 14.
Where an ownership interest in an exploration and evaluation asset is exchanged for another, the transaction is recognised by reference to the
carrying value of the original interest. Any cash consideration paid, including transaction costs, is accounted for as an acquisition of exploration
and evaluation assets. Any cash consideration received, net of transaction costs, is treated as a recoupment of costs previously capitalised with
any excess accounted for as a gain on disposal of non-current assets. Where a discovered 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.
13. Oil and gas assets
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at beginning of period
Additions
Transferred from exploration and evaluation
Amortisation
Impairment
Carrying amount at end of period
Cost
Accumulated amortisation & impairment
Carrying amount at end of period
Notes
2020
$’000
2019
$’000
14
613,198
54,189
3,145
(26,452)
(28,100)
615,980
769,575
(153,595)
615,980
394,632
236,745
-
(18,179)
-
613,198
712,241
(99,043)
613,198
93
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020
13. Oil and gas assets continued
Accounting Policy
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 14.
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 78 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 14 and Note 15 respectively.
14. Impairment
Exploration and evaluation assets
Oil and gas assets
2020
$’000
79,398
28,100
107,498
2019
$’000
-
-
-
Recoverable amounts and resulting impairment write-downs recognised in the year ended 30 June 2020:
Segment
Recoverable
amount
method
Impairment
Write-downs
$’000
Recoverable
amount
$’000
Exploration and evaluation assets
VIC/RL 13-15
VIC/P44
PEL 92 Exploration
Onshore Otway
Total impairment of exploration and evaluation assets
South-East Australia
South-East Australia
Cooper Basin
South-East Australia
FVLCD
FVLCD
FVLCD
FVLCD
Oil and gas assets
Casino Henry
Total impairment of oil and gas assets
South-East Australia
FVLCD
Total impairment of exploration and evaluation and oil and gas assets
98,600
28,000
nil
20,982
94,500
41,700
29,100
7,836
762
79,398
28,100
28,100
107,498
94
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 14. Impairment continued
Exploration and evaluation impairment
VIC/RL 13-15
The FVLCD of VIC/RL 13-15 was determined based on expectations of the estimated future cash flows required to develop the Manta 2C
resource and those estimated cash flows arising from use of the asset. A pre-tax discount rate of 10.6% has been applied, reflective of the risks
specific to an asset in the exploration and evaluation phase. In addition, a portion of value is ascribed to the Manta deep prospective resource
based on multiples and risking of discounted cash flows. Other relevant assumptions are outlined in the Significant Accounting Judgements,
Estimates and Assumptions section that follows. The carrying value of VIC/RL 13-15 increased during the year due to increases in the associated
BMG abandonment provision as outlined in Note 15. This increase along with decreases in long-term gas price assumptions have given rise to
an impairment.
Changes in key assumptions to which the recoverable amount is most sensitive would result in higher or lower carrying values as follows:
Resultant impact on carrying value
Long-term gas price: increase/(decrease) of $1/GJ
Discount rate: decrease/(increase) of 1%
Discount rate: decrease/(increase) in risking of Manta Deep of 5%
Capital expenditure: decrease/(increase) of 10%
12-month delay to Manta gas project
VIC/P44
Higher
$’000
35,300
25,400
23,600
22,600
n/a
Lower
$’000
(35,700)
(22,100)
(23,600)
(22,900)
(9,000)
The FVLCD of VIC/P44 was determined based on expectations of the estimated future cash flows required to develop the Annie 2C resource
combined with undeveloped reserves in Casino Henry and from utilising the asset. A pre-tax discount rate of 10.8% has been applied, reflective
of the risks specific to an asset in the exploration and evaluation phase. Other relevant assumptions are those outlined in the Significant
Accounting Judgements, Estimates and Assumptions section that follows. The carrying value of VIC/P44 increased during the year due to
recognition of the Annie gas discovery in accordance with the successful efforts method. Prior to this, the carrying value was comprised mainly
of acquisition costs related to prospective resources in the permit from the acquisition of Santos’ Victorian portfolio of assets. Decreases in long-
term gas price assumptions and preliminary estimates of costs to develop have given rise to an impairment.
Changes in key assumptions to which the recoverable amount is most sensitive would result in higher or lower carrying values as follows:
Resultant impact on carrying value
12-month delay to OP3D project
Long-term gas price: increase/(decrease) of $1/GJ
Discount rate: decrease/(increase) of 1%
Capital expenditure: decrease/(increase) of 10%
PEL 92 Exploration
Higher
$’000
n/a
10,600
4,100
5,300
Lower
$’000
(11,100)
(10,600)
(3,700)
(5,100)
The carrying value of PEL 92 exploration was comprised of carry forward exploration costs in non-producing areas of the PEL 92 area of interest.
The asset has been impaired to nil in line with the absence of budgeted or planned exploration activities in the exploration area of interest.
Onshore Otway
The impairment of exploration assets relates to a specific Onshore Otway area of interest that has been reduced to nil.
Oil and gas asset impairment
Casino Henry
The FVLCD of Casino Henry was determined based on expectations of the estimated future cash flows required to develop undeveloped 2P
reserves in the Henry field combined with the Annie 2C resource and from utilising the asset. A pre-tax discount rate of 8.6% has been applied,
reflective of the time value of money and risks specific to the asset. Other relevant assumptions are those outlined in the Significant Accounting
Judgements, Estimates and Assumptions section that follows.
The impairment of Casino Henry has arisen due to a combination of factors:
• price assumptions for uncontracted gas have been revised to reflect the lower, post-COVID-19 prices currently prevailing and anticipated for
2021, increasing thereafter
• largely uncontracted gas production from 1 January 2021 onwards
• an increase in oil and gas assets associated with upward revisions in abandonment provisions as outlined in Note 15
• an increase in the estimate of costs to develop undeveloped reserves based on pre-select phase cost estimates obtained during the year in
respect of the Otway Phase 3 Development (OP3D) project
• other cost increases
95
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 14. Impairment continued
Changes in key assumptions to which the recoverable amount is most sensitive would result in higher or lower carrying values as follows:
Resultant impact on carrying value
Long-term gas price: increase/(decrease) of $1/GJ
Discount rate: decrease/(increase) of 1%
Capital expenditure: decrease/(increase) of 10%
12-month delay to OP3D project
Sole
Higher
$’000
16,200
8,900
5,600
n/a
Lower
$’000
(16,300)
(8,100)
(5,700)
1,400
The Sole asset was tested for impairment as indicators of impairment existed, notably the delay experienced by APA Group (APA) in
commissioning the Orbost Gas Processing Plant (OGPP). The delay is the result of foaming in absorber vessels of the Sulphur Recovery Unit of
the OGPP, which has impaired gas processing capacity, preventing the plant from producing at nameplate capacity of 68 TJ/d. Additionally, on
20 August 2020, Cooper Energy and APA announced that they had entered into a Transition Agreement (TA) as referenced in Note 30.
The recoverable amount for Sole was assessed on a VIU basis which exceeded the Cash Generating Unit (CGU)’s carrying value of $532.2 million
and therefore no impairment has been recognised. VIU for Sole was determined based on the estimated cash flows arising from use of the asset
on a 2P reserve basis and incorporating terms in the TA. These terms include the completion of Phase 2 Works at the OGPP in the December
2020 quarter in order for the plant to reach nameplate processing capacity levels of 68 TJ/d shortly after, and cost and revenue sharing between
APA and Cooper Energy whilst under the terms of the TA.
Until completion of the Phase 2 works, a processing rate of 40-45 TJ/d has been assumed, being the demonstrated capability of the OGPP to
maintain stable supply. Sales gas processed during this time is assumed to be sold at spot gas prices less transport costs, with term Gas Sales
Agreements (GSAs) assumed to commence in January 2021. The cost of the Phase 2 works has not been finalised, with current estimates
being $15 million (Cooper Energy share $7.5 million).
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 Phase 2 Works
• spot prices realised for gas sold prior to term GSAs commencing
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.
96
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 14. 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. Where
indicators of impairment are present, the Group will test whether the CGU’s recoverable amount exceeds its carrying amount. Relevant items of
working capital and property, plant and equipment are allocated to CGUs when testing for impairment.
The estimated expected cash flows used in the discounted cash flow model are based on management’s best estimate of the future production
of reserves and sales volumes, commodity prices, foreign exchange rates, development expenditure in order to access the reserves, and
operating expenditure.
The Group’s commodity prices and foreign exchange rates for impairment testing are based on management’s best estimates of future market
prices, with reference to external brokers, market data and futures prices. The Group’s gas price assumptions are based on contract prices
applied against contracted gas volumes. The Group’s view of future uncontracted, long-term gas prices has been revised to reflect the lower,
post-COVID-19 prices currently prevailing and is based on market data available such as the ACCC Gas Inquiry, South-East Australia gas market
supply and demand information, oil prices and foreign exchange rates. The Group’s future pricing assumptions in real terms are set out below:
Reporting Period
Key assumption
FY2021
FY2022
Brent crude oil (US$/bbl)
35.00 – 50.00
50.00 – 60.00
FY2023
60.00
FY2024+
60.00
30 June 2020
30 June 2019
Uncontracted gas ($/GJ)
6.00 - 8.00
8.00 – 11.00
Brent crude oil (US$/bbl)
67.50
67.50
67.50
67.50
Uncontracted gas ($/GJ)
9.00 – 12.00
The Group assumes foreign currency exchange rates of A$1/US$0.65 for FY21 and A$1/US$0.68 for subsequent periods.
Discount rates applied in the net present value calculation of the VIU are derived from the weighted average cost of capital. The Group
applied a range of pre-tax real discount rates between 8.6% and 10.8% (2019: 9.03%).
In the event circumstances vary from the assumptions used in the impairment assessment, the recoverable amount of the Group’s assets or
CGUs could change materially and result in further impairment losses. The key variables that impact on asset values are often interrelated and
therefore, changes in individual variables rarely occur in isolation of other changes. Furthermore, management is able to respond to certain
changes in variables and mitigate losses or maximise value depending on the prevailing conditions that exist at the time. Accordingly, while
sensitivities have been provided for specific changes in key assumptions, the indirect impact that a change in one variable has on another is
impractical to estimate, as is the potential for, and size of any further impairment write-downs or reversals in future reporting periods.
97
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 15. Provisions
Current Liabilities
Restoration provisions
Employee 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 (i)
Transferred (to)/from non-current provisions
Carrying amount at end of period
Movement in carrying amount of the non-current restoration provision:
Carrying amount at beginning of period
New provisions and changes in restoration assumptions (i)
Provision through asset acquisition
Transferred from/(to) current provisions
Increase through accretion
Change in discount rate
Carrying amount at end of period
2020
$’000
17,899
2,003
19,902
367
374,304
374,671
2020
$’000
9,989
(2,380)
-
10,290
17,899
276,228
88,473
4,957
(10,290)
4,001
10,935
2019
$’000
9,989
1,142
11,131
561
276,228
276,789
2019
$’000
67,651
(10,112)
1,185
(48,735)
9,989
106,070
98,432
-
48,735
4,902
18,089
374,304
276,228
(i) New provisions recognised is in respect of restoration provisions arising from exploration permits (2019: Sole Horizontal Directional Drilling
(HDD) and pipeline and exploration permits). Changes to restoration assumptions primarily represent changes to gross cost estimates for
restoration work. In the current year, work on the BMG restoration project has progressed, resulting in the Group applying current regulatory
requirements, decommissioning cost data acquired during the period, and taking account of the US dollar exchange rate across the portfolio.
These updated estimates were taken into consideration when the Group reviewed the gross cost estimates for the other wells in the portfolio.
In the current year, the timing of restoration has also changed for a number of non-operated assets.
The abandonment and remediation work on BMG is expected to be completed in the 2023 calendar year subject to rig availability and regulatory
approvals. The abandonment and remediation work on offshore wells and pipelines is estimated to be performed between 2025 to 2045.
The discount rate used in the calculation of the provisions as at 30 June 2020 ranged from 0.24% to 1.72% (2019: 0.96% to 1.82%) reflecting a
risk-free rate that aligns to the timing of restoration obligations. The reduction in the risk-free rate reflects the change in Australian government
bond rates since the last assessment.
98
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 15. Provisions continued
Accounting Policy
Provisions are recognised when the Group has a legal or constructive obligation as a result of past transactions or other past events, 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.
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. 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. 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.
99
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020
16. Leases
The Group has adopted AASB 16 Leases from 1 July 2019. Refer to the New accounting standards and interpretations section for related
transition disclosures.
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 depreciated
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
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
Short-term and low-value lease asset exemptions
For the year ending 30 June 2020, 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
2020
$’000
-
18
18
The Group had total cash outflows for leases of $1.6 million in 2020, including leases for short-term leases and low-value assets. The future cash
outflows relating to leases that have not yet commenced is disclosed in Note 26.
100
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 16. Leases continued
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 14). Lease liabilities are excluded from the carrying amount of a CGU.
At the commencement date of the lease, the Group recognises lease liabilities measured 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 leases
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.
17. Government grants
Reconciliation of government grants at beginning and end of period:
At beginning of period
Grant received during the year
Allocated to exploration and evaluation assets
At end of period
Accounting Policy
2020
$’000
430
-
(430)
-
2019
$’000
2,067
-
(1,637)
430
Grants from the government are recognised at their fair value where there is a reasonable assurance that the grant will be received and
the Group will comply with all attached conditions. Government grants received in relation to exploration and evaluation assets, oil and gas
assets or property, plant and equipment are recognised as a reduction in the carrying value of the asset as expenditure is incurred.
101
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 Funding and Risk Management
18. Interest bearing loans and borrowings
Current bank debt
Non-current bank debt
Net of capitalised transaction costs of $nil (2019: $4.5 million).
2020
$’000
26,000
203,438
2019
$’000
-
213,680
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 2020. A summary of the
Group’s secured facilities is included below.
Facility
Currency
Limit1
Reserve Based Lending Facility
Australian dollars
$250.0 million (2019: $250.0 million)
Utilised amount
$229.4 million (2019: $218.2 million)
Accounting balance
$229.4 million (2019: $213.7 million)
Effective interest rate
6.01% floating
Maturity²
Facility
Currency
Limit
2021 – 2024
Working Capital Facility
Australian Dollars
$15.0 million (2019: $15 million)
Utilised amount3
$1.5 million (2019: $1.7 million)
Accounting balance
Nil (2019: Nil)
Effective interest rate
Nil
Maturity
28 September 2022
1. As at 30 June 2020, $233.0 million of the facility limit of $250.0 million is currently available.
2. Repayment profile based on facility utilisation and reserves profile following completion of the Sole Gas Project
3. As at 30 June 2020, no amounts have been drawn down, but $1.5 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 2020 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
2020
$’000
2019
$’000
1,728
3,398
(4,001)
(4,902)
(37)
(634)
(70)
-
(12,580)
(11,015)
9,665
(7,587)
(5,859)
11,015
(4,972)
(1,574)
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 2020, the Group has utilised $229.4 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
Issuance of shares for Performance Rights and Share Appreciation Rights
Issuance of shares to contractors
At 30 June
Accounting Policy
2020
$’000
2019
$’000
475,862
474,397
2020
2019
Thousands
$’000
Thousands
$’000
1,621,551
474,397
1,601,079
471,837
5,096
-
1,465
-
19,682
790
2,217
343
1,626,647
475,862
1,621,551
474,397
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 2020
20. Contributed equity and reserves continued
Reserves
Consolidation
reserve
$’000
(541)
-
-
-
(541)
-
-
-
Share
based
payment
reserve
$’000
9,586
-
(2,217)
3,422
10,791
-
(1,465)
3,504
(541)
12,830
Consolidated
At 1 July 2018
Other comprehensive expenditure
Transferred to issued capital
Share-based payments
At 30 June 2019
Other comprehensive income/
(expenditure)
Transferred to issued capital
Share-based payments
At 30 June 2020
Nature and purpose of reserves
Consolidation reserve
Option
premium
reserve
$’000
Cash flow
hedge
reserve
$’000
Equity
instrument
reserve
$’000
25
-
-
-
25
-
-
-
25
310
(894)
-
-
(584)
584
-
-
-
545
(989)
-
-
(444)
(690)
-
-
Total
$’000
9,925
(1,883)
(2,217)
3,422
9,247
(106)
(1,465)
3,504
(1,134)
11,180
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.
2020
$’000
(49,931)
(86,029)
(135,960)
2019
$’000
(37,880)
(12,051)
(49,931)
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 2020 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
2020
$’000
564
20,968
21,532
1. The equity instruments consist of two investments and the Group has not received dividends during the financial year.
Other financial liabilities – Current
Derivative financial instruments designated in a hedge relationship
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
-
-
3,642
3,642
3,482
37
123
3,642
2019
$’000
1,252
20,488
21,740
1,758
1,758
3,482
3,482
3,054
70
358
3,482
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.
105
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 21. Financial risk management continued
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
Derivative financial instruments designated
in a hedge relationship
Interest bearing loans and borrowings
Carrying amount
Fair value
Level
2020
$’000
2019
$’000
2020
$’000
2019
$’000
2
1
2
2
3
2
2
19,996
21,169
19,996
564
1,252
564
20,968
20,488
20,968
21,183
3,642
44,533
3,482
21,183
3,642
21,169
1,252
20,488
44,533
3,482
-
1,758
-
1,758
229,438
213,680
230,705
215,566
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 Orbost Gas Processing Plant 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.
Derivative financial instruments designated in a hedge relationship
The derivative financial instruments relate to the Group’s hedging activities to hedge against cash flow risks from movements in interest rates
(and oil price in the prior year), for which hedge accounting has been applied. The derivative financial instruments are measured at fair value
through other comprehensive income and released to profit and loss in line with the hedged item and the fair value is obtained from third party
valuation reports.
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 2020 equalled 0.49% (June 2019: 1.02%). 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 and 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.
106
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 21. Financial risk management continued
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 2020 and 30 June 2019. 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 2020 and 30 June 2019.
a) Foreign currency risk
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. The Group may
from time to time have cash denominated in United States 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
2020
$’000
13,830
2,176
2019
$’000
3,980
5,591
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 2020 of $2.2 million
(2019: $5.6 million).
c) Interest rate risk
The Group has borrowings of $229.4 million at 30 June 2020 (2019: $213.7 million). Interest on borrowings are 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
2020
$’000
2019
$’000
Impact on after tax profit
(1,455)
1,778
397
(397)
(2,294)
2,294
(870)
1,063
656
(656)
-
-
Impact on reserve
56
(56)
125
(125)
107
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 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. There are no amounts provided for based on lifetime expected credit loss from trading customers.
The Group has some exposure to credit loss from other receivables and an amount of $2.4 million calculated on lifetime expected credit loss has
been recognised in respect of a credit-impaired receivable.
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 2020
Trade and other payables
Lease liabilities
Interest bearing loans and borrowings
Success fee financial liability
Less than
3 months
$’000
3 to 12
months
$’000
1 to 5
years
$’000
Greater than
5 years
$’000
21,183
258
2,530
-
-
786
-
6,887
35,192
218,017
-
5,000
-
5,118
-
-
Total
$’000
21,183
13,049
255,739
5,000
23,971
35,978
229,904
5,118
294,971
At 30 June 2019
Trade and other payables¹
41,644
Interest bearing loans and borrowings
Success fee financial liability
Derivative financial liabilities designated
in a hedge relationship
-
-
-
-
9,490
-
1,758
-
235,262
5,000
-
-
15,763
-
-
41,644
260,514
5,000
1,758
1. Excludes deferred lease incentive
41,644
11,248
240,262
15,763
308,916
108
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 22. Hedge accounting
The Group uses interest rate swaps to manage its exposure to fluctuations in interest rates. The swaps are designated as cash flow hedges and
are entered into for a period consistent with the exposure of the underlying transactions.
Cash flow hedges – interest rate swaps
Interest rate swaps measured at fair value through other comprehensive income are designated as hedging instruments in cash flow hedges of
forecast interest payments in respect of the Group’s reserve base lending facility.
Carrying amount
$nil (2019: $1.8 million liability)
Notional value
Hedge cover
Maturity date
Average hedged rate
$nil (2019: $161.7 million)
Nil (2019: 74%)
N/A
N/A
The fair value of the swaps varies based on changes in forward rates.
Fair value of interest rate swaps
30 June 2020
30 June 2019
Assets
$’000
-
Liabilities
$’000
Assets
$’000
Liabilities
$’000
-
-
1,758
The terms of the interest rate swaps match the terms of the expected highly probable forecast interest payments.
The cash flow hedges of the expected future interest payments were assessed to be highly effective and a net unrealised gain of $2.1 million
(2019: $1.3 million net unrealised loss) and a tax expense of $0.4 million (2019: tax benefit of $0.4 million) relating to the hedging instrument are
included in OCI. $1.2 million has been reclassified to the profit and loss in the current period.
Accounting Policy
Derivatives are initially recognised at their fair value when the Group becomes a party to the contract. Derivative financial instruments
measured at fair value through profit and loss may be designated as hedging instruments in a hedge relationship.
Cash flow hedges
The Group uses interest rate swaps as hedges of its exposure to interest rate risk in forecast transactions. Amounts recognised as other
comprehensive income are transferred to profit or loss when the hedged transaction affects profit or loss – when the sale occurs or when
interest is paid.
Hedge effectiveness is determined at the inception of the hedge relationship and through periodic prospective effectiveness assessments
to ensure an economic relationship exists between the hedged item and a hedging instrument. The Group enters into hedging relationships
where the critical terms of the hedging instrument match exactly with the terms of the hedged item and so a qualitative assessment of
effectiveness is performed. If changes in circumstances affect the terms of the hedged item such that the critical terms no longer match exactly
with the critical terms of the hedging instrument, the Group uses the hypothetical derivative method to assess effectiveness.
The effective portion of the gain or loss on the hedging instrument is recognised in other comprehensive income in the cash flow hedge
reserve while any ineffective portion is recognised immediately in the statement of profit or loss.
If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, or when the hedge no longer meets the
criteria for hedge accounting, any cumulative gain or loss previously recognised in other comprehensive income remains separately in equity
until the forecast transaction occurs.
109
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 Group Structure
23. Interests in joint arrangements
The Group has the following interests in joint arrangements involved in the exploration and/or production of oil and gas in Australia:
Ownership Interest
2020
2019
Joint Arrangements in Australia in which Cooper Energy Limited is the operator/manager
VIC/L24 & 30
Gas exploration and production
50%
50%
Joint Arrangements in Australia in which Cooper Energy Limited is not the operator/manager
PEL 90K
PEL 93¹
PRL 237
Oil and gas exploration
Oil and gas exploration and production
Oil and gas exploration
-
30%
20%
25%
30%
20%
PRL 207-209 (Formerly PEL 100)
Oil and gas exploration
19.165%
19.165%
PRL 183-190 (Formerly PEL 110)
Oil and gas exploration
PEL 494
PEP 150
PEP 168
PEP 171
PRL 32
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.
Accounting Policy
20%
30%
50%
50%
75%
30%
25%
20%
30%
50%
50%
75%
30%
25%
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;
• When the arrangement is structured through a separate vehicle, the Group also considers 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.
110
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020
24. 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
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
Note
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
Ownership interest
2020
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
2019
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).
(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, CE Nabeul Ltd, Cooper Energy (BMG) Pty Ltd, Cooper Energy (CB) Pty Ltd and Cooper Energy (Finance)
Pty Ltd were inactive during the current and prior year, therefore the Financial Statements of the consolidated entity also represent the closed
group results.
(c) Asset acquisition
On 1 May 2018, the Casino Henry Joint Venture participants entered into an agreement to acquire the BHP’s 90% interest in the Athena Gas Plant
from the Minerva Joint Venture on cessation of current operations processing gas from the Minerva gas field. This transaction completed on
4 December 2019 and is when control passed.
111
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 24. Investments in controlled entities continued
The table below shows the assets acquired as part of the transaction.
Consideration transferred
Inventory
Property, plant and equipment
Restoration provision
Net assets acquired
Accounting Policy
2020
$’000
4,113
396
8,674
(4,957)
4,113
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.
25. 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)/Profit of the parent entity
Total comprehensive (loss)/gain of the parent entity
112
2020
$’000
114,686
638,845
14,891
192,562
475,862
(42,794)
25
12,830
445,923
(39,302)
(39,302)
2019
$’000
179,179
597,200
22,683
120,522
474,397
(8,535)
25
10,791
476,678
1,250
1,250
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 Other Information
26. Commitments for expenditure
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
2020
$’000
32,300
68,944
-
2019
$’000
20,722
33,544
-
101,244
54,266
2020¹
$’000
24,273
242,729
112,398
379,400
2019²
$’000
1,584
6,866
896
9,346
1. Commitments relating to leases that have not yet commenced
2. Relates to operating lease commitments under non-cancellable office lease. Refer to the transition disclosures within the new accounting
standards and interpretations section for reconciliation of lease commitments disclosed to the lease liability recognised on transition to
AASB 16 Leases.
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 2020 the Parent entity has bank guarantees for $1.5 million (2019: $1.7 million). These guarantees are in relation to performance
bonds on exploration permits and guarantees on office leases.
Accounting Policy
The determination of whether an arrangement is or contains a lease is based on the substance of the arrangement and requires an assessment
of whether the fulfilment of the arrangement is dependent on the use of a specific asset or assets and the arrangement conveys a right to use
the asset.
Operating lease payments are recognised as an expense in the Consolidated Statement of Comprehensive Income on a straight-line basis over
the lease term.
The Group has entered into commercial property leases. The Group has determined that is does not obtain any of the significant risks and
rewards of ownership of these properties and has thus classified the leases as operating leases.
This accounting policy was only applicable for the 2019 year.
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.
113
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 27. Share based payments continued
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
8 December 2017
12 December 2018
12 December 20181,2
15,898,978
13,312,848
-
11 December 2019
14,871,802
11 December 20192
-
1. Granted in December 2018 and exercised in December 2019
2. Relates to deferred STIP performance rights granted
6,330,443
4,888,166
697,284
4,257,209
769,605
$0.310
$0.435
$0.435
$0.575
$0.575
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
Number of Share
Appreciation Rights
Number of Performance
Rights1
2020
38,457,469
14,871,802
2019
46,017,694
13,312,848
2020
15,464,897
5,026,814
2019
17,846,179
5,585,450
(5,049,246)
(19,269,412)
(2,613,107)
(7,296,874)
- expired and not exercised
- forfeited following employee termination
-
-
-
-
(1,603,661)
(15,975)
(51,439)
(618,419)
Balance at end of year
Achieved at end of year
48,280,025
38,457,469
17,862,629
15,464,897
-
-
-
-
1. Includes deferred STIP issued as performance rights
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.
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
8 December
2017
12 December
2018
11 December
2019
12.4 cents
29.5 cents
1.94%
56%
0%
14.5 cents
43.5 cents
1.95%
49%
0%
15.8 cents
57.5 cents
0.68%
40%
0%
8 December
2017
12 December
2018
11 December
2019
22.4 cents
29.5 cents
1.94%
56%
0%
30.0 cents
43.5 cents
1.95%
49%
0%
37.7 cents
57.5 cents
0.68%
40%
0%
114
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020
27. Share based payments continued
Accounting Policy
The Group provides benefits to employees of the Group in the form of share-based payment transactions, whereby employees render services
in exchange for rights over shares (“equity-settled transactions”).
The cost of these equity-settled transactions with employees is measured by reference to the fair value at the date at which they are
granted and are recorded as an expense, with a corresponding increase in reserves, on a straight-line basis over the vesting period of the
related instrument.
The fair value is determined using the Black-Scholes methodology to produce a Monte-Carlo simulation model that takes into account the
exercise price, the vesting period, the vesting and performance criteria, the 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.
28. Related party disclosures
The Group has a related party relationship with its joint arrangements (Note 23), its subsidiaries (Note 24), 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
2020
$
2019
$
5,906,298
6,038,132
47,513
244,725
105,207
225,178
2,263,996
2,122,499
8,462,532
8,491,016
115
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020
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
2020
$
2019
$
511,395
511,395
187,915
187,915
699,310
390,425
390,425
193,650
193,650
584,075
30. Events after the reporting period
On 20 August 2020, Cooper Energy and APA executed a Transition Agreement which outlines terms for the parties to work together to complete
the commissioning of the Orbost Gas Processing Plant (OGPP), and commence firm supply to Cooper Energy’s term gas customers as early
as possible.
The Transition Agreement supplements the existing agreements and sets aside potential claims and entitlements available to either party. It also
provides for the sharing of operating costs, capital costs (Phase 2 works) and revenue whilst OGPP commissioning proceeds towards completion.
116
Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 Directors’ Declaration
In accordance with a resolution of the Directors of Cooper Energy Limited, I state that:
1.
In the opinion of the Directors:
(a) the financial statements and notes of the consolidated entity are in accordance with the Corporations Act 2001, including:
(i) giving a true and fair view of the consolidated entity’s financial position as at 30 June 2020 and of its performance for the year ended
on that date; and
(ii) complying with Australian Accounting Standards (including the Australian Accounting Interpretations) and the Corporations
Regulations 2001;
(b) the financial statements and notes also comply with International Financial Reporting Standards as disclosed in the Basis of
Preparation; and
(c) there are reasonable grounds to believe that the consolidated entity will be able to pay its debts as and when they become due
and payable.
2. This declaration has been made after receiving the declarations required to be made to the Directors in accordance with section 295A of the
Corporations Act 2001 for the financial year ended 30 June 2020.
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 24 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.
Mr John C. Conde AO
Chairman
31 August 2020
Mr David P. Maxwell
Managing Director
117
118
119
120
121
122
123
124
125
Ernst & Young
121 King William Street
Adelaide SA 5000 Australia
GPO Box 1271 Adelaide SA 5001
Tel: +61 8 8417 1600
Fax: +61 8 8417 1775
ey.com/au
Auditor’s Independence Declaration to the Directors of Cooper Energy
Limited
As lead auditor for the audit of the financial report of Cooper Energy Limited for the financial year ended
30 June 2020, I declare to the best of my knowledge and belief, there have been:
a) no contraventions of the auditor independence requirements of the Corporations Act 2001 in
relation to the audit; and
b) no contraventions of any applicable code of professional conduct in relation to the audit.
This declaration is in respect of Cooper Energy Limited and the entities it controlled during the financial
year.
Ernst & Young
L A Carr
Partner
Adelaide
31 August 2020
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
126
Securities Exchange and Shareholder Information
as at 31 August 2020
Listing
The company’s shares are quoted on the Australian Securities Exchange under the code of “COE”.
Number of Shareholders
There were 8,147 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 2020)
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
53
20
1,036
2,184
1,226
3,080
621
8,147
309,644
5,944,146
10,066,459
108,845,086
1,501,482,063
1,626,647,398
0.02
0.37
0.62
6.69
92.31
100.00
Total Performance Rights
17,862,629 Performance Rights
48,280,025 Share Appreciation Rights
Unmarketable Parcels
There were 1,579 members, representing 1,017,466 shares, holding less than a marketable parcel of 1,516 shares in the company.
Twenty Largest Shareholders
Rank Name
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
JP Morgan Nominees Australia Pty Limited
HSBC Custody Nominees (Australia) Limited
Citicorp Nominees Pty Limited
National Nominees Limited
BNP Paribas Nominees Pty Ltd
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