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2018 Annual Report
Cooper Energy Limited
ABN 93 096 170 295
Cover: Flow testing of Sole-3, the first of two new production wells spudded in the Gippsland Basin during the year to bring a new source
of gas supply to south-east Australia from July 2019. The completion of Sole-3 and Sole-4 after year-end was the successful culmination of
workstreams across the company during the year, spanning financing, legal, subsurface, technical, procurement, development, drilling,
safety and environment and project management.
This report features photographs of operations on the Diamond Offshore Ocean Monarch drilling rig and support craft on location at Sole.
Annual Report
This document has been prepared to
provide shareholders with an overview
of Cooper Energy Limited’s performance
for the 2018 financial year and its outlook.
The Annual Report is mailed to shareholders
who elect to receive a copy and is available
free of charge on request (see Shareholder
Information printed in this Report).
The Annual Report and other information
about the company can be accessed
via the company’s website at
www.cooperenergy.com.au
Notice of Meeting
The 2018 Annual General Meeting of Cooper
Energy Limited ABN 93 096 170 295 (“the
company”) will be held at 10.30 am (ACDT)
on Thursday, 8 November 2018 in the
PwC Building, Level 11, 70 Franklin Street,
Adelaide, South Australia.
The Notice of Meeting has been mailed to
shareholders. Additional copies can
be obtained from the company’s registered
office or downloaded from its website at
www.cooperenergy.com.au
Abbreviations and terms
This Report uses abbreviations and terms
relevant to the company’s accounts and
the petroleum industry.
The terms “the company” and “Cooper
Energy” and “the Group” are used in this
report to refer to Cooper Energy Limited
and/or its subsidiaries. The terms “2018”,
“FY18” and “2018 financial year” refer to
the 12 months ended 30 June 2018 unless
otherwise stated. References to “2017”,
“FY17, FY19” or other years refer to the
12 months ended 30 June of that year.
Other abbreviations
bbl: barrels of oil
boe: barrels of oil equivalent
bopd: barrels of oil per day
$: Australian dollars
FEED: front end engineering and design
FID: final Investment decision
FTE: full time equivalent
GJ: gigajoules
HSEC: Health, safety, environment
and community
kbbl: thousand barrels
km: kilometres
LNG: liquefied natural gas
LTI: lost time injury
LTIFR: lost time injury frequency rate
m: metres
MMbbl: million barrels of oil
MMboe: million barrels of oil equivalent
NOPSEMA: National Offshore Petroleum
Safety and Management Authority
NOPTA: National Offshore Petroleum
Title Administrator
PJ: petajoules
PRMS: Petroleum Resources
Management System
SCF: standard cubic feet
SPE: Society of Petroleum Engineers
TJ: terajoules
TRIFR: Total recordable injury
frequency rate
1C: Low Estimate Contingent Resources
2C: Best Estimate Contingent Resources
3C: High Estimate Contingent Resources
1P: Proved Reserves
2P: Proved and Probable Reserves
3P: Proved, Probable and Possible Reserves
VWAP: volume weighted average price
Reserves and resources
Cooper Energy reports its reserves and
resources according to the SPE (Society of
Petroleum Engineers) Petroleum Resources
Management System guidelines (PRMS).
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.
Contingent resources are those quantities
of petroleum estimated, as of a given date,
to be potentially recoverable from known
accumulations but the applied project(s)
are not yet considered mature enough for
commercial development due to one or
more contingencies.
In PRMS, the range of uncertainty is
characterised by three specific scenarios
reflecting low, best and high case
outcomes from the project. The terminology
is different depending on which class
is appropriate for the project, but the
underlying principle is the same regardless
of the level of maturity. In summary, if the
project satisfies all the criteria for Reserves,
the low, best and high estimates are
designated as proved (1P), proved plus
probable (2P) and proved plus probable
plus possible (3P), respectively. The
equivalent terms for contingent resources
are 1C, 2C and 3C.
Rounding
Numbers in this report have been rounded.
As a result, some figures may differ
insignificantly due to rounding and totals
reported may differ insignificantly from
arithmetic addition of the rounded numbers.
Cooper Energy
We find, develop and commercialise oil and gas.
We do this with care and strive to provide
attractive returns for our shareholders and good
commercial outcomes for our customers.
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 7 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
Our business
We generate revenue from the discovery,
commercialisation and sale of gas to
south-east Australia and low cost 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 development decision within
5 years; and
• are value accretive.
Production FY18
1.49 MMboe
0.27
Proved and Probable Reserves
52.4 MMboe at 30 June 2018
Contingent Resources
23.6 MMboe at 30 June 2018
1.8
10.0
0.1
3.1
1.22
40.6
20.4
Gippsland Basin gas
Cooper Basin oil
Otway Basin gas and gas liquids
Other key statistics:
For the year ended 30 June 2018
Market capitalisation:
Net cash/(debt):
Issued shares:
Shareholders:
$616 million
$111 million
1,601.1 million
6,622
Employees and contractors:
101 full time equivalent
2
Offshore Otway Basin:
Gas production and exploration
• Casino Henry gas production and development
• Minerva gas field
• Minerva Gas Plant
• VIC/P44 exploration
Gippsland Basin:
Offshore gas development and exploration
• Sole Gas Project
• Manta gas and liquids resource
• VIC/P72 exploration permit
Darwin
Perth Office
Brisbane
Adelaide
Office
Sydney
Melbourne
Onshore Otway Basin:
Gas exploration
• Gas exploration acreage
• Extends over Sawpit sandstone play fairway
and surrounds Haselgrove discovery
Hobart
Cooper Basin:
Onshore oil production
• Western flank oil production and exploration
3
Key results
Financial
• Sales revenue up 73%, chiefly due to increased gas volumes and assisted by
higher oil and gas prices.
• Statutory profit of $27.0 million includes significant items of $17.2 million, including
gain on sale of Orbost Gas Plant.
• Return to profit at statutory and underlying profit levels after tax.
• Balance sheet cash and debt up due to Sole project funding and draw-downs.
Sales revenue
$ million
Statutory net profit after tax
$ million
Underlying net profit after tax
$ million
9.8
67.5
27.0
39.1
39.1
27.4
-12.3
-34.8
-63.5
-1.3
-2.8
-8.7
2015
2016
2017
2018
2015
2016
2017
2018
2015
2016
2017
2018
Net cash from operating activities
$ million
Net cash/(debt)
$ million
Shareholders equity
$ million
22.2
147.4
111.0
443.9
285.0
7.9
4.1
2.0
49.8
39.4
103.9
91.6
2015
2016
2017
2018
2015
2016
2017
2018
2015
2016
2017
2018
4
Operations and reserves
• Zero lost time injuries, zero serious injuries, zero reportable environmental incidents.
• Production up 54%, with full year contribution from gas assets acquired in FY17.
• Proved and probable reserves up 348%; Sole FID and upgrades from
field performance.
Safety
Lost time injury frequency rate
Production
MMboe
Proved and probable reserves
MMboe
1.0
1.49
0.96
52.4
0.48
0.46
0.0
0.0
0.0
11.7
3.1
3.0
2015
2016
2017
2018
2015
2016
2017
2018
2015
2016
2017
2018
Equity
Share price
cents at 30 June
24.5
21.5
Basic earnings per share
cents
Market capitalisation
$ million at 30 June
38.0
38.5
1.8
-1.8
-10.1
-19.2
616
433
81
94
2015
2016
2017
2018
2015
2016
2017
2018
2015
2016
2017
2018
5
Overview of operations,
exploration and development
Otway:
Value adding development and gas contracting.
Plant acquisition agreement.
• Production increase at Casino
Henry by workover of Casino-5
gas well
• New gas supply contract
for supply from Casino Henry to
Origin Energy from 1 March
2018 to 31 December 2018
• Minerva gas production
exceeding expectations: reserves
upgrade and field life extension
• Gas plant acquisition
agreement for Casino Henry JV
to acquire Minerva Gas Plant
on fulfilment of conditions
• Exploration and development
analysis and planning for
drilling in FY19 and FY20: Henry
development; offshore and
onshore exploration drilling
Cooper Basin:
Increased production. Strong cash margin.
• Production: oil production
up 8%
• Direct operating cost:
A$33.05/bbl vs average oil
price A$85.55/bbl
• Drilling: 2 unsuccessful
exploration wells drilled
Minerva Gas Plant
6
Callawonga storage facility
Gippsland:
Sole Gas Project proceeding, exploration
acreage acquired.
• Sole Gas Project FID occurred
29 August 2017 with securing
of funding
• Orbost Gas Plant agreement
completed in October providing
for APA Group to acquire and
upgrade the plant to process
Sole gas and access for Manta
• Project on schedule: Sole
Gas Project advanced to 56%
complete at 30 June
• Key milestones completed
include shore crossing and
drilling of production wells after
year-end
• Project safety record: offshore
drilling campaign completed
without lost time injuries
or environmental incidents
• Manta gas and gas liquids
appraisal and exploration
preparations advanced for
drilling in FY20
• Exploration acreage acquired:
VIC/P72, adjacent to existing
acreage and in proximity to Sole
and Orbost Gas Plant
Supply vessel Sea Swan and Diamond Offshore Ocean Monarch drilling rig
Production:
12 months to 30 June
2018
2017
Gas
PJ
Oil
million barrels
Total
MMboe
Gas
PJ
Oil
million barrels
Total
MMboe
Otway Basin
7.0
Cooper Basin
Indonesia
-
-
-
0.27
-
1.22
0.27
-
4.0
-
-
-
0.25
0.03
0.68
0.25
0.03
• FY19 outlook: Sole project
completion scheduled for June,
preparation for Manta drilling,
VIC/P72 study and analysis
7
From the Chairman
John Conde AO
transformational growth in its production, cash flow and earnings
and of delivering the first new offshore gas supply to south-east
Australia in 6 years. It is our expectation shareholder value
recognition will accompany progress in the Sole Gas Project. This
was evidenced post year-end by the improvement in the company’s
share price following completion of the project’s production wells.
Safety continues to be our top priority and operating with care for
health and safety, the environment and our communities is one
of our core values. We have retained this focus on the safety of our
staff, our contractors and the communities in which we operate,
embracing the added demands the company’s development
continues to bring for safe management of our operations.
The 2018 financial year brought marked expansion in the scope,
risk profile and nature of your company’s responsibilities. Apart
from taking on the role of Operator from 1 July 2017 for a number of
offshore permits, activities undertaken included the conduct of an
offshore drilling campaign and a range of onshore work for the Sole
Gas Project including pipe welding, earthworks and the drilling of
two shore crossings. This was completed without lost time injuries,
serious injuries or reportable environmental incidents.
However, as this report documents, the occurrence of two contractor
restricted work cases meant our performance ultimately fell short
of the injury-free and incident-free performance to which we aspire.
The board is committed to an injury-free and incident-free
performance and we will continue to encourage all employees
and our contractors to strive for this outcome.
As set out in the opening page of this report, Cooper Energy is a
values-driven organisation. The values stated and elaborated
have been a longstanding feature of the company, its culture and
decision-making process. Accordingly, it was pleasing the company’s
inaugural staff engagement survey conducted after year-end
confirmed an exceptionally high level of engagement and awareness
and acceptance of the Cooper Energy Values and their importance
in generating shareholder value.
We were pleased to welcome Ms Elizabeth Donaghey to the board
in June. Ms Donaghey brings to your board extensive experience,
including as a director, within the Australian energy sector.
In particular, her experience in gas commercialisation, strategy
and portfolio management, sustainability and regulatory matters is
directly relevant to your company’s present and future needs.
We thank the Managing Director, David Maxwell, and his team of
executives and staff for their contribution to what has been
a landmark year for your company, positioning us on the cusp
of substantial growth. Congratulations all!
Finally, I thank my colleagues on the board and our Company
Secretary for their counsel, effort and support and for the many
unscheduled meetings and discussions the year’s activities required.
This annual report is the most pleasing I have had the honour
of presenting as the chairman of your company. There are three
reasons for this.
First, as this document details, the growth and progress during the
12 months to 30 June has been exceptional in almost every metric
of financial and technical performance.
Profit and cash generation have improved several times over.
Production was 54% higher and exceeded expectations at the start
of the year. Proved and Probable reserves were more than 4 times
greater than at the start of the year. The company’s financial position
and outlook at year-end were strong.
Secondly, and more significantly, I am conscious Cooper Energy
shareholders placed their trust in the execution of a long-term
strategy under which a company, which had no gas assets, would
build a gas business to address supply opportunities expected to
emerge in six or more years’ time.
I am pleased this report, the first documenting a full 12 months’
performance as a predominantly gas business, demonstrates clear
progress and benefits brought by this strategy.
At year-end this progress had not translated fully to shareholder
value as measured by share price, which grew by 1.3% to
30 June compared to the 42% increase in market capitalisation.
Total Shareholder Return, inclusive of the discounted share
offers made as part of the Sole Gas Project funding, was 6.0%.
The discrepancy between the growth in market capitalisation
and share price during the year is due to this capital issue,
which secured conservative funding from top-tier Australian and
international banks and the Final Investment Decision for the Sole
Gas Project. While the increased share base has diluted prices per
share, we are confident the forging of relationships with a quality
banking group and the calibre of the finance package secured will
benefit shareholders in the medium and long terms.
Thirdly, the outlook for the coming years foreshadowed in this report
is particularly promising.
John Conde AO
Chairman
After six years of strategy development, portfolio building, planning
and funding, your company is now within 12 months of realising
8
On-board the Ocean Monarch, a subsea wellhead is prepared for deployment
on the seabed. The wellhead is 5 metres high and weighs 35 tonnes.
9
Managing Director’s Report
Putting a good set of results in the right context and
our preparations for ‘growth after Sole’.
David Maxwell
2018
The 12 months to 30 June 2018 proved to be the most significant
year for Cooper Energy since its incorporation.
2018 was the year the company made the commitments, received
the necessary approvals and executed agreements which underpin
its transformation from a minority interest onshore oil producer
to an operator, developer and explorer of offshore gas for south-
east Australia.
The approvals, commitments and agreements formalised during the
year included:
- regulatory approvals and acceptances for assumption of the role
of Operator for our Sole and Casino Henry projects, the associated
pipeline interests and our offshore exploration acreage;
- funding agreements secured with senior bank lenders;
- Final Investment Decision (FID) for the Sole Gas Project;
- agreement with APA Group (“APA”), for APA to acquire, upgrade
and operate the Orbost Gas Plant to process gas from Sole, and
later, Manta and other fields;
- new sales agreements for Casino Henry gas, the first since the
company acquired the asset and the first since agreements struck
when the field commenced production in 2006; and
- agreement for the Casino Henry joint venture to acquire the
Minerva Gas Plant.
Cooper Energy is now positioned and equipped to deliver the
shareholder value targeted by the gas strategy to which the company
committed in 2012.
It is important to understand this expectation is based on more
substantive factors than simply building a gas business to capture
supply opportunities.
The focus on building a business best able to generate shareholder
value from the opportunity in south-east Australian gas has given
Cooper Energy 3 ‘competitive edges’ which, in combination,
differentiate the company from its peers and are expected to drive
value creation in the coming 2 to 3 years:
1) the growth profile from Sole. The Sole Gas Project is scheduled to
underpin an increase in gas production over 2018 levels of more
than 3 times in its first full year of operation, with flow-on gains
in revenue and cash generation. Sole is projected to add gas sales
of 24 petajoules per annum on commencement which compares
to Cooper Energy’s total FY18 gas output of 7 petajoules.
Subsea wellhead enters the waters of Bass Strait as it is lowered
for installation on the Sole-4 production well, 125 metres below surface.
Fellow shareholders,
Your company’s annual results for 2018 are the best yet recorded
by Cooper Energy.
Among the highlights are its highest production, strong financial
results and its greatest growth in Proved and Probable reserves.
However, while annual reports necessarily focus on a 12-month
period, the building of businesses and creation of sustainable
shareholder value is a longer-term exercise.
The achievements featured in this report have emerged from
the execution of a strategy, over six years, by a stable, committed
management team, backed by a supportive loyal shareholder
base, to build a portfolio-style gas business addressing supply
opportunities in south-east Australia. And while it is pleasing to
report the results this enabled in 2018, we are mindful genuine
value creation for our shareholders requires ongoing, and
greater, improvement.
Cooper Energy is well placed to deliver this; the results for 2018
are but a small, and second-year, instalment of the six-year growth
profile expected from the company’s existing developed assets and
projects. However, critical assessment of your company’s capacity to
deliver sustained improvement requires more than the simple year-
on-year comparisons that occupy an annual report.
In this, my sixth annual report, I will address our position at year-end
and review the progress, suitability and resourcing of our strategy.
10
11
Managing Director’s Report
David Maxwell
2) the competitiveness of our gas portfolio and volume of
uncontracted gas. Cooper Energy’s reserves include one of
the larger inventories of uncontracted gas, located in the
most competitive sources of supply for south-east Australia.
Your company is among the very best placed to bring gas to
this tightly supplied region. Moreover, the capacity to portfolio
manage supply across two hubs in the Otway and Gippsland
basins enables Cooper Energy to optimise its supply for
best returns.
3) incumbency as an existing operator in the most competitive
sources of gas supply for south-east Australia. Our status as
one of the few offshore Operators of oil and gas assets in offshore
southern Australia, positions Cooper Energy as one of the small
number of companies ready, with the necessary resources and
the history of compliance relevant for exploration, development
and production of gas offshore Victoria. As a result, the company
offers greater value and desirability as a partner in the region
and possesses advantages in the ease, speed and cost with
which it can address local opportunities. This is enhanced further
by the access to infrastructure Cooper Energy holds through
its agreements for processing at the Orbost Gas Plant and the
agreement to acquire the Minerva Gas Plant.
Leveraging of these advantages commenced in FY18 with the
tendering of Casino Henry gas supply for the 2018 calendar year
and is expected to accelerate in FY19. The conclusion of a new gas
supply agreement for Casino Henry gas for the 2019 calendar year,
the tendering of uncontracted gas from Sole and the safe completion
of the Sole Gas Project to budget are among the events projected
to be value-adding in the new year.
Operating with care and sustainably
The growth of our business has brought attendant growth in the
scope, and depth, of the obligations we assume in choosing
to operate with care for the health and safety of our people, the
environment and communities with which we are involved.
In 2018 this involved the performance of 491,111 hours of work
by employees and contractor staff including offshore workover
and drilling operations in the Otway and Gippsland basins, support
of these campaigns through the Port of Melbourne supply base
and site construction works at the Orbost Gas Plant for the
shore crossings.
The conduct of operations that were safe and environmentally
responsible, is but a small outcome of the larger task involved in
planning, documentation, consultation, securing regulatory
approval, exercise drills, testing, review and improvement. Assuming
operatorship of offshore licences, and the obtaining of approvals
necessary for a 120-day drilling campaign in 3 locations, required
extensive work to secure regulatory acceptance of the company’s
safety and environmental management plans. The safe execution of
the drilling program without environmental incident is a noteworthy
accomplishment for which I would like to record the company’s
commendation to all involved.
In terms of measured performance, the company completed the
year with no serious injuries, environmental or process safety
incidents. There were two restricted work-related incidents
involving contractor employees which resulted in a total recordable
injury frequency rate of 4.07 for the 12 months to 30 June, which
compares to 1.98 for the preceding 12 months, and the industry
standard of 4.02 as measured by NOPSEMA (National Offshore
Petroleum Safety and Environmental Management Authority).
Discussion of these results is provided in more detail under the
heading ‘Safety’ on page 19.
A safe workplace requires no serious harm to our workers, 365
days of the year. The company achieved this and is committed
to maintaining this standard. We are conscious a sustainable
business demands more than compliance to the minimum safety,
environmental and social standards considered necessary. The past
18 months have been necessarily focussed on rapid attainment
of regulatory compliance and safe execution. We have now elevated
our aspirations to the achievement of ‘best in class’ standards.
Capital management
The financial close of the $265 million bank facilities in October
2017 was a milestone for the company. The facilities, which
completed funding for the Sole Gas Project, were underwritten
by ANZ and Natixis, with ABN AMRO, ING and NAB joining via
subsequent syndication.
The participation of top-tier banks and the terms of the facility
reflect favourably on the credit quality of the Sole project and of
Cooper Energy.
The principal facility, a $250 million reserve-based lending
facility extends over the life of the field. I would like to record our
appreciation to the members of our banking syndicate for the long-
term commitment they have made to the company which enabled
the development of the cornerstone project for our growth plans.
It is our expectation the banking facility and the relationships
we have established with senior banks will prove important in the
execution of our growth plans in the coming years.
Future growth
The progression of the Sole Gas Project towards its scheduled
completion by July 2019 has been accompanied by increasing work
on the company’s next wave of growth.
A number of opportunities for production uplift from 2020 onwards
are present within our portfolio. While these cover a range of
exploration, appraisal and development opportunities, all share
the competitiveness characteristics that enhance development
prospects and value creation: proximity to existing infrastructure,
proximity to market and relatively low capital costs.
12
Concluding comments
Your company has concluded the 2018 financial year with the Sole
project fully funded and advancing to its July 2019 start-up and the
transformative uplift in production, revenue and cash generation
this will bring.
Having reached this position, our focus in 2019 will be on efficient
execution and operating safely in accordance with our values of
care, integrity, fairness and respect, transparency, collaboration,
awareness and commitment.
While our year-end reserves and outlook are the strongest yet for
Cooper Energy we are mindful value for shareholders requires the
potential of our portfolio to be realised.
I want to acknowledge and record my thanks to the staff and
contractors who have made the pleasing results of 2018 possible.
David Maxwell
Managing Director
Preparations have commenced for the conduct of a drilling
campaign to address these opportunities which include:
- Henry development; this well is to address approximately 24 PJ
of undeveloped proved and probable reserves net to Cooper
Energy and lift field production. The well would be connected at
the first opportunity and is expected to provide an immediate
uplift in production.
- Manta-3; to be drilled as a precursor to a development decision
on the Manta Gas Project. Manta is 100% owned by Cooper
Energy and offers a second-stage and synergistic gas and liquids
development to the nearby Sole gas field. It is considered Manta
could be developed to commence production from FY23, subject
to rig availability, drilling and development outcomes.
Access to gas processing at the Orbost Gas Plant has been
secured under the existing agreement with APA and there is
customer interest in the availability of Manta gas. Subject to the
results of Manta-3, it is considered the field’s contingent resources
of 106 PJ to 111 PJ of gas and 3.2 million barrels of condensate
can be developed via a subsea project similar to that being applied
at Sole. The well also has an exploration purpose, as it will address
the deeper, larger, prospective gas resource discussed on page 33.
- gas exploration targets in the company’s offshore Otway Basin
acreage where success rates are high and infrastructure is
in place. As discussed in the Review of Operations on page 31,
analysis has identified a number of attractive prospects which are
considered likely to be economic for development given the
proximity to established pipelines and the availability of the Minerva
Gas Plant on completion of its acquisition from BHP Billiton
Petroleum (Victoria) Pty Ltd.
These opportunities offer significant increments to our gas
production in the period 2020 to 2025. More importantly, it is
considered each opportunity satisfies the company’s 3-step screen
for value generating capital expenditure: a superior position on
the cost curve; economics which are value generating and either
in production or likely to be ready for a development decision
within 5 years.
The potential of these opportunities, coupled with south-east
Australia’s ongoing gas requirements, underpin Cooper Energy’s
firm conviction the existing portfolio has the ingredients to deliver
the company’s next wave of growth after Sole. Our exploration and
development activities for the coming 12 to 24 months will be
directed to transforming these opportunities into committed growth
projects. The question of strategy and our future opportunities are
examined in a broader context on the following pages.
13
Strategy and the delivery of
value for shareholders.
6 questions, 6 years in.
In 2012 the company elected to reorient its strategy from onshore Cooper
Basin oil production and international exploration to build a portfolio style gas
business to address supply opportunities foreseen emerging in eastern Australia
following the commencement of LNG manufacture and export.
Six years on, it is appropriate to review the strategy and its progress. Managing
Director David Maxwell addresses six questions on its ongoing relevance,
shareholder benefits and the future.
1. The gas strategy was launched 6 years ago.
3. So what is the company’s position now?
Is it still appropriate?
The underlying premise of the strategy adopted in 2012 has been
proven correct, albeit conservative.
The gap between forecast south-east Australian gas demand and
available supply has emerged earlier and larger than anticipated.
Gas prices have also been higher than anticipated. Our gas assets
are considered to be among the lowest cost supply options for
south-east Australia for the foreseeable future. The more we
examine the assets we have acquired, the more opportunities we
see to underpin sustained growth in production and value.
2. Is the company progressing satisfactorily
against its strategy and its opportunity
horizon?
We are tracking ahead of where we expected to be. Remember,
we had no gas reserves, gas contracts or gas prone exploration
acreage when we committed to our gas strategy. Our equity in our
principal gas assets in the offshore Otway and Gippsland Basin
is 50% to 100%, much higher than we had anticipated, and we
are also Operator for these assets.
The four years to 2016 were concerned with patient compilation
of assets that met our criteria for value generation and the
orderly divestment of non-core assets. By January 2017, we
had assembled a portfolio of gas production, exploration and
development assets in the Otway and Gippsland basins.
From 2017, the focus has been on funding and development.
The company is on track to be producing gas from both the Otway
and Gippsland basins by mid-2019, all from Cooper Energy-
operated assets. Completion of the Sole Gas Project at this time
and of the Henry development well later in the year will have
our gas production growing and the capacity to apply a portfolio
approach to supply.
When should shareholders expect to see the
delivery of value targeted by the strategy?
We now have the foundation portfolio in place for execution
of the strategy and we expect these assets will be delivering
transformative production and financial growth within 12 months.
Our expectation is this should be reflected in the value of the
company’s securities, as should the de-risking of the Sole project
as it nears completion. The 29% increase in the share price in the
8 weeks following the completion of the first of the Sole production
wells is illustrative of this.
4. Should there be a change in strategy given
the company has progressed from an
aspiring gas supplier to an established gas
supplier to south-east Australia?
Our strategy for creating shareholder value is essentially
unchanged: a portfolio style gas business generating the bulk of
its revenue from the supply of gas to south-east Australia from
resources that occupy a highly competitive position on the cost
curve; that are value adding; and that are either in production or
have clear plans for production within 5 years.
The qualification on competitiveness, value accretion and
development timelines are critical for our business model. Only the
most competitively placed resources can generate the best returns
to shareholders and the best commercial outcomes for customers.
This remains the bedrock of our strategy. What does change is the
focus and scale of our activities.
With the foundation in place, the focus of our activities has shifted
to efficient exploration, development, excellence in operations and
gas contracting so we get the best value for our shareholders –
whilst at all times ensuring we manage and conduct our operations
every day with care.
14
6. Does Cooper Energy have the resources to
deliver on its strategy?
This is a question we continue to ask ourselves and we work hard
to make sure the answer is “yes”. It is a question which extends
beyond financial capability; along the journey we have had
to assess, build, prove and test our technical, managerial and
operational depth.
We have been fortunate to have acquired a proven team of
employees and contractors. This team has driven what has been a
successful drilling work program at Casino and Sole this year. We
have been rounding out our team with appointments where needs
are identified, staying disciplined in making sure Cooper Energy
stays a lean organisation, works consistent with our Cooper Energy
Values whilst being fit for purpose.
Developing our people, attracting good people and working with
experienced capable contractors has been an important part of
our success – and we don’t plan on changing this. This approach
has been critical, as our journey from being a company with a
market capitalisation of $50 million in January 2016 proposing to
develop the $605 million Sole Gas Project, could seem daunting
to some.
At Sole, the involvement of blue-chip partners, customers, suppliers
and contractors such as APA, AGL, EnergyAustralia, Alinta, O-I, GE,
Diamond Offshore, Subsea7 and Technip along with senior bankers
ANZ, Natixis, ABN AMRO, ING and NAB, has created a low risk,
soundly-based project that is conservatively and fully financed.
Our financial capacity will expand substantially with the completion
of the Sole Gas Project and the boost from cash generated by the
commencement of gas supply from Sole. We expect this to support
the execution of our drilling campaign commencing in 2019 and our
development plans at Henry and the Minerva Gas Plant.
We are continuing to develop and grow our portfolio, as resource
companies must. We continue to evaluate opportunities that meet
our criteria, most recently adding the VIC/P72 exploration acreage
that adjoins some of our existing acreage and infrastructure in
the Gippsland Basin.
5. What about after Sole?
Our expectation and planning now is for a ‘second wave’ of
production growth from our existing portfolio from 2022/2023.
The preparation of an offshore drilling campaign to address these
opportunities has been identified as one of our most important
workstreams for FY19.
We have commenced engagement with rig contractors for a
program which is expected to include appraisal and exploration
drilling on the Manta gas field and, subject to joint venture
approval, the drilling of the Henry development well and at least
2 exploration wells in the offshore Otway Basin. We expect the
drilling campaign will commence some time in calendar 2019,
at a date that will be largely determined by rig availability.
Our development concept for Manta is advancing and has
benefited from the work done on Sole, our existing infrastructure
at Patricia-Baleen and access agreements for the Orbost Gas
Plant. Success at Manta-3 should see FID for that project within
12 months thereafter.
Our offshore Otway acreage is particularly attractive for gas
exploration and development. Its exploration merit is enhanced
by the clarity of seismic data, the number of prospects and the
drilling success rate in a proven gas province. The development
attractiveness is enhanced by the proximity of existing pipeline
and competitive processing infrastructure. Our subsurface
team is working hard to identify the best targets for the VIC/P44
joint venture to consider and select for drilling in the approaching
offshore drilling program.
Our commitment to acquire the Minerva Gas Plant from BHP
is indicative of the promise we see for further gas development in
the Otway Basin.
It is worth reflecting on the features of the plant that suggest
its strategic and financial value will increase significantly in
the coming years: it is an established gas plant with available
processing capacity, offering competitive processing costs, at
low inlet pressure, to the existing fields nearby and is located in
a proven gas producing province that has the highest success
rate for offshore gas exploration in southern Australia.
We also plan to participate in the drilling of an onshore well in the
South Australian Otway Basin in FY19.
15
2018 Sustainability Review
Cooper Energy is committed to operating with care
and seeks to impart a legacy of positive social,
environmental and economic outcomes through its
operations and behaviours.
The company’s objective is to be a sustainable
business that delivers value for shareholders,
customers, employees and the communities in
which it works.
The pursuit of sustainability is conducted through
two dimensions: firstly, in the present, by seeking
to operate with excellence 365 days a year, at
every location where the company is involved; and
secondly, in building better outcomes in the future
through continual improvement in performance.
The company’s efforts are guided by the
sustainability principles developed and applied
across 4 key areas: people; safety; environment; and
community and stakeholders. The opportunities,
obligations and exposures in each of these areas
expanded substantially with the company’s
development during the year.
Cooper Energy’s transition from a non-operating
onshore oil producer to the Operator of numerous
offshore petroleum titles with operations ranging
from exploration, project development, production
and care and maintenance has brought new
requirements and risks to be carefully managed
in the interests of sustainability.
This review, is just one of a number of governance
and reporting measures instituted for monitoring,
managing, reporting and improving the company’s
performance in building a sustainable business.
At the board level, the governance of performance
in promoting and achieving sustainability has been
given extra focus through the formation of a specific
Risk and Sustainability Committee. Under the
guidance of the Risk and Sustainability Committee,
the company developed a Sustainability Policy and
prepared this Sustainability Review for inclusion
in the 2018 Annual Report, to explain the approach
taken, and performance and areas of future focus.
This sustainability review is the first by Cooper
Energy. The company looks forward to building the
scope and depth of its reporting and to publishing
performance and progress on an annual basis in
future years’ Sustainability Reviews.
16
Ocean Monarch conducting flow-back operations
on the Sole gas field, VIC/L32, Gippsland Basin
17
2018 Sustainability Review
Safety
The last 12 months has seen Cooper Energy mature as an operator. The expansion
in the scope and nature of Australian operations brought increased activity, work
hours and contractor management requirements and increased exposure to risk.
This expansion was executed without a single Lost Time Injury (LTI) or serious
injury being recorded during the year.
Hydrogen sulphide safety drill on-board Ocean Monarch
18
Key Performance Indicators
Lost Time Injury Frequency Rate
Total Recordable Injury Frequency Rate
Recordable Incidents
Serious Injuries
Process Safety Incidents
Work Hours Australian Operations
Work Hours Total
FY18
0
4.07
2
0
0
491,111
491,111
FY17
0
1.98
1
0
0
58,312
506,298
Cooper Energy takes a proactive approach to the achievement of
and maintenance of an incident-free, safe performance, every day,
at every location it is operating. Fundamental to the creation and
maintenance of a safe work place is the application of the corporate
values as a guiding tool for all decisions made, followed by
disciplined performance in the workplace so performance aligns
with our objectives.
Safety performance
Personal safety performance is measured in terms of the total
recordable injury frequency rate (TRIFR) and lost time injury
frequency rate (LTIFR). Cooper Energy recorded a TRIFR of 4.07
in line with the NOPSEMA industry average. There were two
restricted work cases involving contractor employees. Both these
cases were soft tissue injuries with the workers making full
recoveries. Of note, is zero lost time incidents and no serious
process safety incidents during the year.
Every day should be incident-free and although there were no
serious injuries throughout the year, the lessons learnt from
all incidents and near misses have helped Cooper Energy to take
proactive steps to strengthen safety performance.
Performance summary during the year
P No Lost Time Injuries
P No serious recordable injuries
P No serious process safety incidents
P Ongoing refinement of management systems
P Successful launch of a cloud-based emergency response
platform for collaboration across locations
P Positive regulator evaluation of HSEC systems
Future focus
¢ Ongoing refinement of HSEC systems
¢ Improved leading key performance indicators to drive
compliance and continual improvement
¢ Refined measurement of incident investigation metrics
¢ Timely close-out of action items identified in audits
¢ Strengthen contractor HSEC evaluation and onboarding
19
2018 Sustainability Review
Environment
Cooper Energy is committed to doing no environmental harm through proactive
planning and management of all campaigns.
The operation of the company’s first offshore drilling campaign required
the preparation, approval and implementation of comprehensive and detailed
environmental management plans. The drilling campaign was completed
with no spills to the environment.
Environmental performance
Performance summary
There were no reportable incidents1 in Cooper Energy’s operations
during the year.
Cooper Energy’s implementation of its no harm policy has focussed
on two elements during the year:
1. Implementation of systems that capture potential impacts and
risks to the environment (during activity pre-planning risk
assessments); identifying and managing these risks with
mitigating control measures to the industry standard level of
ALARP (“as low as is reasonably practical”), a level that meets
environmental commitments as detailed in the Environment
Plans submitted to and accepted by the Commonwealth and
State regulators; and
2. Expanding environmental expertise to ensure coverage and
knowledge across diverse areas of operation, both onshore
and offshore.
P No reportable environmental incidents
P No environmental spills or serious environmental incidents
P No environmental improvement or infringement notices
P Growing in-house environmental expertise
Future focus
¢ Consolidate offshore environmental documentation
¢ Streamline environmental commitments
¢ Focus on bioregions
¢ Continue to protect sensitive environments
1. A reportable environmental incident means an incident relating to
the activity that has caused or has the potential to cause moderate
to significant environmental damage. These are defined in the title-
holder’s environment plan.
Key measures
Key performance indicator
Environmental Spills
Regulator Environmental Inspections
Serious Environmental Incidents
Environmental Improvement Notices
FY18
0
2
0
0
FY17
0
1
0
0
20
East Gippsland shoreline. Cooper Energy’s operations during the year
required the preparation of comprehensive environmental management plans
for marine and shoreline environments in the Gippsland and Otway Basins.
21
2018 Sustainability Review
Our People – One Team
FY18 was a period of exciting and
transformational growth. The significant
contribution of people and the focus
on what needs to be achieved and how
to achieve these objectives are equally
important. Workforce capability has
strengthened and priorities for further
organisation development are identified.
At Cooper Energy, values are at the heart of the organisation’s culture.
The Cooper Energy Values are the guiding principles which describe
what the company stands for and how the business operates.
The company scorecard recognises that people enable performance
and working together as one team is an important foundation for
company success. A high performing work environment is evident,
and the high level of engagement and enablement has greatly
assisted the business during a period of transformational growth.
In July 2018 Cooper Energy conducted an employee engagement
and enablement survey to calibrate the status of the company’s
work environment and culture.
Engagement
The survey recorded an overall engagement score of 74%; a result
which indicates high level of commitment, willingness to contribute
additional effort and strong desire for success by the organisation.
Cooper Energy’s score benchmarks favourably against international
and industry results. Comparison against Korn Ferry Hay Group’s
international benchmark data indicates employee engagement at
Cooper Energy consistent with the international benchmark for high
performing organisations and above the level recorded for the oil and
gas sector and within general industry. The survey has established
that, overall, people feel proud to work for Cooper Energy and have
highly favourable expectations of the success of the organisation
over the coming 2 to 3 years.
Enablement
Enablement measures the extent to which skills and abilities
of people are utilised and whether the work environment supports
people to perform work requirements. Cooper Energy achieved
an enablement score of 70%, indicating confidence amongst staff
in their ability to work effectively at Cooper Energy. The enablement
score recorded for Cooper Energy aligns with Korn Ferry Hay
Group’s international benchmarks for the oil and gas sector and
above the general industry benchmark.
Overall, the engagement and enablement survey has provided
valuable insights and data on organisational strengths
and opportunities. There is ongoing focus on organisational
strengths and further work ahead to unlock opportunities for
enhanced performance.
22
Diversity and inclusion
Cooper Energy has an inclusive culture and the gender mix within
the permanent workforce is 35% female and 65% male. There is
female representation at all levels of the organisation. The July 2018
survey received consistent, clear and wide-ranging evidence that
‘people at Cooper Energy are given fair treatment without regard to
race, colour, age, national origin and religion’.
Talent and resourcing
The permanent staff full time equivalent (FTE) increased by 44%
from 27 persons to 39 persons during the FY18 period. The primary
work locations are Adelaide and Perth. A further 75 casual and
contractor staff provided support during the FY18 period. A number
of external service providers continue to provide specialist services
under the terms of procurement contracts.
The growth in the workforce included a successful transfer of staff
from Santos to Cooper Energy in July 2017 as part of the acquisition
of the Victorian asset portfolio and in September 2017, the transfer
of plant operators from Cooper Energy to APA Group as part of the
sale of the Orbost Gas Plant.
Taking time out on the helideck on the Ocean Monarch, from left: Paul Lawrence,
Cooper Energy HSE Offshore Coach; Daniel Van Wanrooy, Cooper Energy Offshore Logistics Co-ordinator;
Peter Bennett, Cooper Energy Senior Drilling Supervisor; and Pip Burr, Cooper Energy Drilling Supervisor
Cooper Energy has a comprehensive approach to recruitment and
high standards. The recruitment strategy is focussed on the hire
of capable and experienced people to support organisation growth.
The Managing Director and the Management Team are actively
engaged in the interview process to ensure the right people with the
right skills, education, experience and competency are hired and to
ensure candidates are aligned with the company values.
Cooper Energy’s reputation in the employment market is strong and
high calibre candidates continue to express an interest in joining
the organisation.
In FY18, the planning phase for succession and talent management
commenced. The transformational growth period has provided
significant opportunity for people to grow and for people to feel a
real sense of achievement which has been key to the retention of the
workforce. Employee turnover for the 2018 financial year was 8%,
slightly below industry and general standards.
Health and wellbeing
Cooper Energy has an Employee Assistance Program in place
which provides professional counselling and support to assist people
in dealing with the challenges of their daily work and family lives.
The program, which is available to staff and contractors and their
families, focusses on health and well-being and is available 24 hours
a day, 7 days a week. During FY18 the program scope included
onsite counselling and support on grief and loss and practical
sessions for the management of stress.
A Volunteer Policy provides leave opportunities for employees to
make a difference in the community.
A commitment to care and legacy was recognised and celebrated
during the year.
Accomplishments
Two employees were awarded industry-based scholarships to attend
the 2018 World Gas Conference held in Washington DC with a focus
on “Fuelling our Future”.
23
2018 Sustainability Review
Community and stakeholders
Cooper Energy recognises stakeholder engagement is an ongoing process
which builds relationships, enables information exchange and achieves mutually
acceptable outcomes.
Cooper Energy is mindful of its responsibilities to the communities in which its
operations are conducted, both as a community member and through the exercise
of its corporate value of care.
Community and stakeholder performance
Key measures
Throughout the year, Cooper Energy advanced its stakeholder
awareness and coverage program to align with expanded acreage
across both the offshore and onshore Otway Basin regions and
the Gippsland Basin. The company identified new stakeholders,
including communities, businesses and government bodies
and issues of relevance to the conduct of operations with which
to engage and understand.
Cooper Energy has adopted an open, active and timely approach
to consultation and has sought to recognise the position of
the stakeholder and the importance of collaboration. Ongoing
initiatives are in place to ensure engagement with communities
on many levels including; distribution of project flyers, coordinating
stakeholder focus group and marine awareness meetings. Cooper
Energy provides up-to-date information accessible via its website’s
community page and expanded the company’s social media
footprint to utilise platforms such as LinkedIn, Twitter and
YouTube for timely and accessible sharing of announcements
and activity information.
Cooper Energy plans to uphold this commitment in future years,
maintaining communication and the reflection of its values of
awareness, transparency and integrity during planning of activities,
supported by the monitoring of ongoing performance with
stakeholder communities.
Calibration measures for the company’s performance in community
and stakeholder engagement were still to be developed at the time
of printing this report. Development and implementation of metrics
for community and stakeholder engagement is planned for FY19.
Performance summary
P Stakeholder management plan for structured communication
with stakeholders in Sole Gas Project
P Increased stakeholder consultation
P Expanded social media footprint to allow greater transparency
to operations
Future focus
¢ Raising awareness and presence in local communities
¢ Development of metrics and increased monitoring
of performance
24
Sunrise, offshore Victoria, looking north to Gippsland. Cooper Energy’s
operations involve the company in engagement with local communities,
fishing industry and recreational stakeholder groups.
25
Reserves and Resources
Reserves
Cooper Energy’s 2P Reserves at 30 June 2018 are assessed to be 52.4 million barrels of oil equivalent (MMboe). This is a 42.2 MMboe
year-on-year increase from 30 June 2017, and a decrease of 1.7 MMboe from 2P Reserves reported on 25 August 2017 following the
Sole FID update. The key factor contributing to the year-on-year revision is the declaration of the Final Investment Decision (FID) for the
Sole gas project and reclassification of Sole Contingent Resources as Reserves.
Reserves at 30 June 2018
Category
Unit
1P (Proved)
2P (Proved and probable)
3P (Proved, Probable and Possible)
Developed Undeveloped
Total
Developed Undeveloped
1. 1.
Total
Developed Undeveloped
Total
Sales Gas
PJ
Oil + Cond
MMbbl
Total 1, 2
MMboe
15
1.1
3.6
235
0.1
38.5
251
1.2
42.1
26
1.4
5.7
283
0.4
46.7
309
1.8
52.4
36
1.9
7.8
350
1.4
58.6
386
3.3
66.4
1. The reserves exclude Cooper Energy’s share of future fuel usage. See comment on conversion factor change in ‘Notes on Calculation of Reserves and
Resources’.
2. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by arithmetic sum by category. As a result, the 1P estimate
may be conservative and the 3P estimate may be optimistic due to the effects of arithmetic summation.
Movement in reserves (MMboe)
Category
Proved (1P)
Proved and Probable (2P)
Proved, Probable and Possible (3P)
Reserves at 30 June 2017 1
FY18 Production 2
Revisions
Reserves at 30 June 2018 3
7.9
(1.5)
35.7
42.1
1. As announced to the ASX on 29 August 2017.
11.7
(1.5)
42.2
52.4
18.7
(1.5)
49.2
66.4
2. Otway Basin and Cooper Basin production from 1 July 2017 to 30 June 2018 (inclusive). The reserves exclude Cooper Energy’s share of future fuel usage.
3. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by arithmetic sum by category. As a result, the 1P estimate may
be conservative and the 3P estimate may be optimistic due to the effects of arithmetic summation. See comment on conversion factor change in ‘Notes on
Calculation of Reserves and Resources’.
Contingent Resources
Cooper Energy’s 2C Contingent Resources at 30 June 2018 have decreased since 30 June 2017 by 54.0 MMboe to a total of 23.6 MMboe.
The key material factors contributing to the revision are:
• Declaration in August 2017 of the Final Investment Decision (FID) for the Sole Gas Project and the company securing a fully underwritten
finance package to complete funding for the project. Sole Contingent Resources therefore were reclassified as Reserves; and
• Contingent Resources previously carried for the Basker field have been reclassified as Discovered Unrecoverable Resources due
to approval of field abandonment.
26
Contingent Resources at 30 June 2018
Category
Basin
Gippsland
Otway
Cooper
Total 1
1C (P90)
Oil/Cond
MMbbl
Total
MMboe1
1.7
0.0
0.1
1.8
12.7
2.0
0.1
14.8
Gas
PJ
68
12
0
80
2C (P50)
Oil/Cond
MMbbl
Total
MMboe 1
3.2
0.0
0.1
3.4
20.4
3.1
0.1
23.6
3C (P10)
Oil/Cond
MMbbl
5.3
0.0
0.2
5.5
Total
MMboe1
32.0
4.6
0.2
36.8
Gas
PJ
165
28
0
193
Gas
PJ
106
19
0
125
1. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by arithmetic sum by category. As a result, the 1C estimate may
be conservative and the 3C estimate may be optimistic due to the effects of arithmetic summation. See comment on conversion factor change in ‘Notes on
Calculation of Reserves and Resources’.
Year-on-year movement in Contingent Resources (MMboe)
Category
Contingent Resources at 30 June 2017 1, 2
Revisions
Contingent Resources at 30 June 2018 1, 2
1C
56.3
(41.5)
14.8
2C
77.6
(54.0)
23.6
3C
108.5
(71.7)
36.8
1. Contingent Resources at 30 June 2017 as reported to the ASX on 29 August 2017.
2. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by arithmetic sum by category. As a result, the 1C estimate may
be conservative and the 3C estimate may be optimistic due to the effects of arithmetic summation. See comment on conversion factor change in ‘Notes on
Calculation of Reserves and Resources’.
Notes on calculation of reserves and resources
Cooper Energy has completed its own estimation of Reserves and
Contingent Resources for its fully-operated Gippsland Basin assets, and
elsewhere based on information provided by the permit Operators (Beach
Energy Ltd for PEL 92, Senex Ltd for Worrior Field; and BHP Billiton
Petroleum (Vic) P/L for Minerva field); in accordance with the definitions
and guidelines in the Society of Petroleum Engineers (SPE) 2018
Petroleum Resources Management System (PRMS).
All Reserves and Contingent Resources figures in this document are net to
Cooper Energy.
Petroleum Reserves and Contingent Resources are prepared using
deterministic and probabilistic methods. The 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. Totals may not exactly reflect arithmetic addition
due to rounding.
The company has changed the FY18 energy conversion factor consistent
with Society of Petroleum Engineers (SPE) conversions and PRMS
guidance. The previous conversion factor of 1 PJ = 0.172 MMboe was
adopted when the company was predominantly a Cooper Basin oil
producer. With the change to a predominantly offshore gas-producing
company, a conversion factor of 1 PJ = 0.163 MMboe (5.8 MMBtu/bbl) is
more consistent with industry and SPE standard energy conversions.
The new conversion factor has no impact on gas reserves expressed in PJ.
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) and exclude reserves used for
field fuel.
The Cooper Basin totals comprise the arithmetically aggregated PEL 92
project fields and the arithmetic summation of the Worrior project reserves,
and exclude reserves used for field fuel.
The Gippsland Basin total comprises Sole gas field only, where the
Contingent Resources assessment at 30 June 2017 as announced to the
ASX on 29 August 2017 has been reclassified to Reserves.
Contingent Resources
Under the SPE PRMS 2018, “Contingent Resources are “those quantities
of petroleum estimated, as of a given date, to be potentially recoverable
from known accumulations by application of development projects, but
which are not currently considered to be commercially recoverable owing
to one or more contingencies”.
The Contingent Resources assessment includes resources in the
Gippsland, Otway and Cooper basins. The following material Contingent
Resources assessment was released to the ASX:
• Manta field on 16 July 2015
Cooper Energy is not aware of any new information or data about Manta
that materially affects the information provided in that release, and all
material assumptions and technical parameters underpinning the Manta
estimates provided in the release continue to apply.
Basker field Contingent Resources reported on 18 August 2014 and
carried unchanged through FY17 have been reclassified as Discovered
Unrecoverable in FY18 due to approval of field abandonment.
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 and 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 5.41, and has consented to the
inclusion of this information in the form and context in which it appears.
27
Review of Operations
Production
Cooper Energy’s oil and gas production
for the year totaled 1.49 MMboe compared
with 0.96 MMboe in the previous year.
The increase is due to the twelve month
contribution from gas assets in the
Otway Basin acquired on 1 January 2017
and increased oil production from the
Cooper Basin.
Drilling
The company participated in 4 wells
during the year; two exploration wells in the
Cooper Basin, two development wells in
the Gippsland Basin and a workover of the
Casino-5 well in the Otway Basin.
Both of the exploration wells were plugged
and abandoned. The development wells,
Sole-3 and Sole-4, were both spudded prior
to year-end and completed subsequently as
future gas producers.
Type
Exploration
Exploration
Area
Tenement
Well
Result
Cooper Basin
PRL 102
Louth-1
Cooper Basin
PEL 93
Frey-1
Sole-3
Sole-4
P&A
P&A
Gas producer
Gas producer
Development
Gippsland Basin
VIC/L32
Development
Gippsland Basin
VIC/L32
Production by region
MMboe
0.27
1.22
0.03
0.25
0.68
0.05
0.54
0.08
0.40
0.14
0.32
2014
2015
2016
2017
2018
Otway Basin, Australia
Cooper Basin, Australia
South Sumatra, Indonesia
28
ROV (remotely operated underwater vehicle)
Operator at work on Ocean Monarch.
29
- a 50% interest in, and
• Condensate kbbl
Review of Operations
Offshore Otway Basin
The company’s interests in the
offshore Otway Basin include:
- a 50% interest in, and
Operatorship of, the producing
Casino Henry Netherby
(“Casino Henry”) Joint Venture
production licences (VIC/L24
and VIC/L30);
Operatorship of, retention
leases VIC/RL11 and VIC/RL12;
- a 50% interest in, and
Operatorship of, the VIC/P44
exploration permit; and
- a 10% interest in the Minerva
gas project comprising offshore
production licence VIC/L22
and the Minerva Gas Plant,
onshore Victoria.
The plant is subject to an
agreement signed by the
Casino Henry joint venture
participants and BHP Billiton
Petroleum (Victoria) Pty Ltd for
the acquisition of the Minerva
Gas Plant by the joint venture
participants on cessation of the
current operations processing
gas from Minerva. The
transaction is also subject to
completion of regulatory
approvals and assignments.
30
Offshore Otway Basin Production
Casino Henry
By Project
FY18
FY17
Casino Henry
• Gas PJ
• Condensate kbbl
Minerva
• Gas PJ
By Product
• Gas PJ
• Condensate kbbl
5.73
2.98
1.31
3.20
7.04
6.18
3.28
1.96
0.75
1.70
4.03
3.66
Offshore Otway Basin 2P Reserves
FY18
FY17
Developed
• Gas PJ
Undeveloped
• Gas PJ
Total
• Gas PJ
26
35
61
13
43
56
The Casino Henry gas operations produce
gas and gas liquids 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 metres to 71 metres.
The licences are covered entirely by high-
quality 3D seismic surveys acquired
between 2001 and 2007. The hydrocarbon
reservoirs discovered and produced to date
are in the Cretaceous Waarre Formation.
The depth of the top Waarre Formation
at the discovered fields ranges between
1,460 metres and 2,030 metres.
Casino Henry consists of a subsea
development comprising four producing
wells (Casino-4, Casino-5, Henry-2 and
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. Gas from
Casino Henry is currently sold to Origin
Energy under a contract that extends to
31 December 2018.
A workover of the Casino-5 well, which had
been shut in since May 2017 was completed
on 25 April 2018. The workover was
successful, with daily gross field production
from the field increasing from the average of
26.7 TJ/day prior to an average of 33.2 TJ/
day for the balance of the financial year.
Adelaide
Warrnambool
PEP 168 (50%)
VIC/RL12 (50%)
VIC/RL11 (50%)
Halladale
Black Watch
Cooper Energy
tenement
Gas field
Gas pipeline
VICTORIA
Melbourne
Iona Gas Plant
VIC/P44 (50%)
Martha
Minerva Gas Plant (10%*)
VIC/P44 (50%)
VIC/L30 (50%)
Henry
Netherby
Minerva
VIC/L22 (10%)
Casino
VIC/L24 (50%)
0
10
kilometres
VIC/P44 (50%)
Otway 98AR18
Undeveloped fields and
exploration
Permit Year 5 of the VIC/P44 exploration
permit was extended to May 2019.
Significant exploration potential is
considered to exist in the offshore Otway
acreage. Thirty-three exploration prospects
have been identified, the majority of which
are the same play type as current producing
gas fields. The majority of the prospects
are located less than 10 km from tie-in
points to the existing offshore production
pipeline, offering simple and close access
to production infrastructure for future
exploration success.
Further investigation of the potential of
these prospects was conducted during the
year through processing of the VIC/P44
3D seismic survey to produce a Quantitative
Interpretation seismic inversion volume
which was integrated into other exploration
studies. Several exploration prospects have
been identified and work to select at least
two targets for the planned offshore drilling
campaign is progressing.
Retention Leases VIC/RL11 and VIC/RL12
contain part of the undeveloped Black
Watch gas field which has been mapped
to straddle the leases and the adjoining
VIC/L1(V) production licence held by Beach
Energy Limited. This licence, which extends
landward to the Victorian coastline, also holds
the Halladale and Speculant gas fields which
have been developed as onshore production
operations through extended reach wells
from shore. Beach Energy has announced
its intention to develop the VIC/L1(V) section
of Black Watch in the same manner.
A production licence application for the
portion of the Black Watch field located
within the VIC/RL11 and VIC/RL12 tenements
is being prepared for consideration by
the regulator.
Potential for further production increase
exists through development of undeveloped
reserves in the Henry gas field. The joint
venture is progressing planning for a
development well, as a sidetrack of
Henry-2, for this purpose. It is expected
the development well will be drilled as part
of an offshore campaign to commence in
2019 subject to rig availability and joint
venture approval.
Minerva
The Minerva gas field is located in
production licence VIC/L22 located 9 km
offshore Victoria in a water depth of 58
metres. The field was discovered by the
current operator, BHP Billiton, in 2002.
The project consists of two subsea
development wells (Minerva-3 and
Minerva-4) tied back to the Minerva Gas
Plant via a 10 inch 14 km trunkline.
Production from the Minerva field
commenced in 2005 and has continued
well beyond expectations, having surpassed
the expected end-of-life in FY18. Current
expectations are that production from
Minerva will extend beyond FY19. Gross
total field production from Minerva in FY18
averaged 35.9 TJ/day.
The Minerva Gas Plant is located
approximately 5 km north-west of
Port Campbell. The plant, which was
commissioned in January 2005, has gas
processing capacity of approximately 150
TJ/day and hydrocarbon liquids processing
facilities. The Minerva Gas Plant is
connected directly to the SEAGas Port
Campbell to Adelaide pipeline and to the
South West Pipeline, owned by APA Group.
31
Review of Operations
Gippsland Basin
Cooper Energy’s interests in the
Gippsland Basin comprise:
- a 100% interest, and
Operatorship of, VIC/L32 which
holds the Sole gas field;
Melbourne
VICTORIA
Orbost
E A
S T E R N GAS P IP E LIN E
Sydney
Orbost Gas Plant
- a 100% interest and
Operatorship of VIC/RL13,
VIC/RL14 and VIC/RL15, which
contain the Manta gas and
liquids resource;
- a 100% interest, and
Operatorship of, VIC/L21,
which contains the 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
permit VIC/P72, awarded in
May 2018.
Gippsland Basin 2P reserves
FY18
FY17
Undeveloped
Lakes Entrance
VIC/L21 (100%)
VIC/P72 (100%)
Patricia-Baleen
VIC/L32 (100%)
Longtom
Tuna
Kipper
Snapper
Marlin
Flounder
Sole
Sole
Manta
Manta
Basker
Chimaera
Gummy
VIC/RL15 (100%)
Fortescue
%)
VIC/RL14 (100%)
VIC/RL13 (100%)
Kingfish
Blackback
Cooper Energy tenement
Gas field
Oil field
Gas well
Gas pipeline
Oil pipeline
0
20
kilometres
Sole pipeline; indicative
Pipeline options
• Gas PJ
249
-
Gippsland_86AR18
32
Sole Gas Project
The Sole Gas Project involves the
development of the Sole gas field and
upgrade of the Orbost Gas Plant to supply
approximately 24 PJ per annum from July
2019. Cooper Energy is conducting the
upstream component which will develop
and connect the gas field. APA Group is
undertaking the upgrade of the Orbost Gas
Plant to process gas from Sole.
The upstream project involves the drilling
and connection of two near-horizontal
production wells, subsea wellheads and
connection of the subsea pipeline and
umbilical controls to the plant via two
horizontal drilled shore crossings.
Work on the project commenced in the
final quarter of FY17 and was taken to
56% complete at 30 June 2018. Progress
to date is within schedule and budget. The
completion testing and suspension of the
production wells Sole-3 and Sole-4 shortly
after year-end marked the fulfillment of a
critical workstream in the project. Reservoir
and well performance during the tests
was consistent with expectations and
with production capability exceeding that
required by plant design.
The remaining workstreams, involving the
welding and installation of subsea pipeline,
manufacture and installation of umbilical
and connection to plant are expected to
be largely accomplished in the first half of
FY19, with commissioning scheduled for the
final quarter of the financial year. First gas
from Sole is expected to be delivered into
the Orbost Gas Plant in the final quarter of
FY19, on which basis first gas sales from
the plant are expected from July 2019.
Gas contracting
The Sole gas field is assessed to hold
2P reserves of 249 PJ. Gas supply from
the field is forecast to be approximately
24 PJ per annum. Approximately 170
PJ of reserves has been contracted to
support funding of the project under long
term sales agreements with AGL Energy,
EnergyAustralia, Alinta Energy and O-I
Australia. Marketing of uncontracted gas
is expected to commence in FY19.
Manta
The Manta gas field is located in retention
licences VIC/RL13, VIC/RL14 and VIC/RL15,
35 km from Sole and 58 km from the Orbost
Gas Plant. The field is assessed to contain
Contingent Resources (2C) of 106 PJ of gas
and 3.2 MMboe of condensate. Prospective
resources are also present at Manta, with
a Best Estimate unrisked prospective
resources of 105 MMboe comprising 526 PJ
of gas, 12.9 MMbbl of condensate and
1.5 MMbbl of oil 1.
The estimated quantities of petroleum
that may be potentially recovered by the
application of future development project(s)
relate to undiscovered accumulations.
These estimates have both an associated
risk of discovery and a risk of development.
Further exploration, appraisal and evaluation
is required to determine the existence of a
significant quantity of potentially moveable
hydrocarbons.
Manta is being considered as a follow-on
development to Sole, with the capability to
produce approximately 24 PJ per annum
plus associated condensate. The field’s
proximity to Sole and the Orbost Gas Plant
enhances its prospects for development.
Analysis has identified significant synergies
and cost savings if Manta is developed
and operated in co-ordination with Sole in
areas including control umbilicals, plant,
redundancies and maintenance. Provision
for Manta gas to access the Orbost Gas
Plant for processing has been incorporated
in the agreements executed by APA Group
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 resources present in deeper
reservoirs. Planning for this well, Manta-3,
has progressed with the expectation
the well would be drilled as part of the
offshore drilling campaign being prepared
to commence in the 2019 calendar year
subject to rig availability.
Patricia Baleen
Patricia Baleen is a largely depleted offshore
gas field located in production licence
VIC/L21 which is in suspension and under
care and maintenance after being shut-in in
2008. The field is connected to the Orbost
Gas Plant by a 24 km pipeline, also owned
by Cooper Energy.
VIC P/72
In May the company was awarded 100%
equity in offshore exploration permit VIC/
P72 for an initial six-year term. The permit
adjoins the company’s VIC/L21 production
licence which holds the depleted Patricia-
Baleen gas field and its associated subsea
production infrastructure connected to
the Orbost Gas Plant.
VIC/P72 is 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 similar
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.
1. As announced to ASX on 4 May 2016.
Cooper Energy confirms that it is not aware
of any new information or data that materially
affects the resource estimate information
included in the announcements and that all
the material assumptions and technical
parameters underpinning the estimates in
the announcements continue to apply and
have not materially changed.
33
Review of Operations
Onshore
Cooper Basin
Cooper Energy holds interests
in three exploration licences,
28 retention licences and eleven
production licences in the
South Australian Cooper Basin.
The company’s activities are
primarily focussed on tenements
held by the PEL 92 Joint Venture
(‘PEL 92‘) on the western flank
of the basin, which provided
approximately 26% of Cooper
Energy’s total production in FY18.
The Worrior Field (PPL 207)
supplied 2% of Cooper Energy’s
total production for the year.
Onshore Otway Basin
Cooper Energy holds interests
in four exploration licences
and one retention licence in the
onshore Otway Basin, covering
a total area of 7,292 km2:
- a 30% interest in PEL 494
and PRL 32, Penola Trough,
South Australia;
- a 20% interest in PEP 150,
Victoria. Since year-end, this
interest increased to 50%
following Beach Energy’s
withdrawal from this permit
and government approval and
registration of the transfer;
- a 25% interest in PEP 171,
Penola Trough, Victoria.
Since year-end, this interest
has increased to 100%
34
2018 operations
The company’s share of oil production
from the Cooper Basin during the year
was 270,000 barrels, 96% of which was
from the PEL 92 Joint Venture. Production
for the 12 months to 30 June was 8%
higher than the previous year, an outcome
which reflects the benefits of development
well drilling conducted in FY17 and reported
in the previous annual report.
Two exploration wells were drilled in the
company’s Cooper Basin acreage during
the year: Louth-1 in PRL 102 and Frey-1 in
PEL 93. Both wells were plugged and
abandoned.
Joint venture and tenement
interests 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;
- a 30% interest in PEL 93 and
PPL 207 which holds the
producing Worrior oil field;
- a 25% interest in PEL 90K;
- a 19.17% interest in the PRL’s
207-209 (ex PEL-100), and
- a 20% interest in the PRL’s 183-
190 (ex PEL-110).
following Beach Energy’s
withdrawal from this permit
and government approval and
registration of the transfer.
Cooper Energy’s interest
may reduce by up to 50%
on fulfillment of farm-in
arrangements executed with
Vintage Energy Ltd during the
year; and
- a 50% interest in PEP 168,
Victoria.
Exploration
The company’s primary focus in the onshore
Otway Basin is exploration of gas plays
associated with the Casterton, Sawpit and
Pretty Hill formations, primarily within the
Penola Trough. Analysis of data from
Jolly-1 ST1 and Bungaloo-1 drilled in 2014
has assisted identification of a number
of opportunities for future evaluation of
the deep plays in the Penola Trough. The
potential of this play was proven during the
year by the new gas field discovery made
by the Haselgrove-3 sidetrack well drilled
by Beach Energy in PPL 62, a licence
surrounded by PEL 494.
During the year the PEL 494 joint venture
was awarded a PACE Gas Round 2 grant
by the South Australian Government of
$6.89 million to drill the Dombey prospect.
Dombey-1 will test the Pretty Hill sandstone
and the deeper Sawpit sandstone where
gas was discovered at Haselgrove and
is scheduled to be drilled during the 2019
financial year.
Activity in the Victorian permits has been
suspended pursuant to the moratorium
imposed by the state government
on onshore petroleum exploration and
production until 30 June 2020.
139°3
139°
140°
Plan area
PRLs 183-190 (20%)
(former PEL 110)
-27°2
-27°
TAS
-27°
Cooper Energy tenement
Other companies’ tenement
Oil field
Gas field
Oil pipeline
Gas pipeline
PRLs 207-209 (19.165%)
(former PEL 100)
e r m ia n edge
C oop
er C
r
P
PEL 90K (25%)
R O U G H
Rincon
North
Rincon
PRLs 85 to 104 (25%)
(former PEL 92)
A
H
P A T C
Callawonga
Elliston
Windmill
Christies
Sellicks
Silver Sands
-28°
Parsons
Perlubie
Germein
Butlers
Lycium Hub
PRL 231 (30%)
(former PEL 93)
PRL 232 (30%)
(former PEL 93)
PRL 233 (30%)
(former PEL 93)
Worrior
PPL 207
PRL 237 (30%)
(former PEL 93)
0
20
40
139°
kilometres
an edge
i
m
r
e
P
140°
Kingston SE
SOUTH AUSTRALIA
Naracoorte
PEL 494 (30%)
PRL 32 (30%)
ROBE TROUGH
Robe
ST CLAIR TROUGH
Beachport
A T
e
e
k
R
R
A
W
MI R I D G E
G
E
M
A
P
P
A
N
G
U
O
R
MOOMBA
A T
G
N
U
L L
A
R O U G H
R I T
-28°
R
H
H
G
U
O
R
A T
R
E
P
P
A
N
E
T
Cooper 83AR18
Cooper Energy tenement
Gas field
Gas pipeline
Depositional trough
PE
N
O
LA
Millicent
Penola
Katnook
Nangwarry
T
R
O
U
G
H
M
Mount Gambier
PEP 171 (100%*)
VICTORIA
ARDONAC
HIE T
R
O
U
G
H
Hamilton
PEP 150 (50%)
PEP 168 (50%)
Cobden
Portland
Warrnambool
Plan area
0
20
40
TAS
kilometres
SHIPWRECK
TROUGH
Otway 97AR18
Otway 97AR18
n
i
s
a
B
r
e
p
o
o
C
t
n
i
s
a
B
y
a
w
O
e
r
o
h
s
n
O
35
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
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)
PEL 90 (Kiwi sub-block)
PRLs 85-104
PRLs 231-233 and 237 1
25%
30%
25%
25%
25%
25%
25%
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
25%
Onshore
25%
25%
25%
25%
30%
Onshore
Onshore
Onshore
Onshore
Onshore
PRLs 207-209
19.17%
Onshore
PRLs 183-190
20%
Onshore
2.0
4.3
6.4
5.5
1.8
2.1
0.1
1.5
2.0
0.8
0.6
Beach Energy
Production
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
144.6
Senex Energy
Exploration
1889.3
Beach Energy
Exploration
621.8
296.5
727.5
Senex Energy
Exploration
Senex Energy
Exploration
Senex Energy
Exploration
1. PRL 237 is subject to a Farmin Agreement which could reduce Cooper Energy’s interest to 20%.
Gippsland Basin
State
Victoria
Tenement
VIC/L21
VIC/RL13
VIC/RL14
VIC/RL15
VIC/L32
Interest
Location
Area (km2)
Operator
Activities
100%
Offshore
134.0
Cooper Energy
Production
(suspended)
100%
100%
100%
100%
Offshore
Offshore
Offshore
Offshore
67.0
67.0
67.0
Cooper Energy
Retention
Cooper Energy
Retention
Cooper Energy
Retention
201.0
Cooper Energy
Development
(for Sole Gas
Project)
VIC/P72
100%
Offshore
269.0
Cooper Energy
Exploration
36
Otway Basin
State
Tenement
Interest
Location
Area (km2)
Operator
Activities
South Australia
PEL 494
Victoria
PRL 32
VIC/L22
VIC/L24
VIC/L30
VIC/RL11
VIC/RL12
VIC/P44
PEP 150
PEP 168
PEP 171
30%
30%
10%
50%
50%
50%
50%
50%
50%
50%
Onshore
Onshore
Offshore
Offshore
Offshore
Offshore
Offshore
Offshore
Onshore
Onshore
2,488.8
Beach Energy
Exploration
36.9
58.0
199.0
200.0
Beach Energy
Exploration
BHP
Production
Cooper Energy
Production
Cooper Energy
Production
127.0
Cooper Energy
Retention
6.0
Cooper Energy
Retention
599.0
Cooper Energy
Exploration
3,212.0
Bridgeport
Exploration
795.0
Beach Energy
Exploration
100%1
Onshore
1,974.0
Cooper Energy
Exploration
1. Subject to Heads of Agreement for a farmin which could reduce Cooper Energy’s interest by up to 50%.
Rig support vessel Far Senator viewed from Ocean Monarch. Support vessels were one of a number of services required to support the offshore campaign.
Other services included helicopter, shore base logistics, fuel supply, specialist drilling contractors, catering and transportation services.
37
Board of Directors
Chairman
Mr John C. Conde AO
B.Sc. B.E(Hons), MBA
Independent Non-Executive Director
Appointed 25 February 2013
Managing Director
Mr David P. Maxwell M.Tech, FAICD
Appointed 12 October 2011
Independent
Non-Executive Director
Ms Elizabeth A. Donaghey B.Sc., M.Sc.
Appointed 25 June 2018
Experience and expertise
Experience and expertise
Experience and expertise
Mr Conde has extensive experience in business
and commerce and in chairing high profile
business, arts and sporting organisations.
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) and the Sydney
Symphony Orchestra (2007 – 2015) and is a
former Director of AFC Asian Cup (2015)
(2012 – 2015).
Previous positions include Non-Executive
Director of BHP Billiton, Chairman of Pacific
Power (the Electricity Commission of NSW),
Chairman of Events NSW, President of the
National Heart Foundation and Chairman of
the Pymble Ladies’ College Council.
Special responsibilities
Mr Conde is Chairman of the Board of
Directors. He is also a member of the
Remuneration and Nomination Committee.
Mr Maxwell is a leading oil and gas industry
executive with more than 25 years in senior
executive roles with companies such as
BG Group, Woodside Petroleum Limited
and Santos Limited. Mr Maxwell has very
successfully led many large commercial,
marketing and business development projects.
Prior to joining Cooper Energy Mr Maxwell
worked with the BG Group, where he was
responsible for all commercial, exploration,
business development, strategy and marketing
activities in Australia and led BG Group’s
entry into Australia and Asia including a
number of material acquisitions.
Mr Maxwell has served on a number of industry
association boards, government advisory
groups and public company boards.
Current and other directorships in the
last 3 years
Mr Maxwell is a Director of wholly owned
subsidiaries of Cooper Energy Ltd.
Special responsibilities
Mr Maxwell is Managing Director and is
responsible for the day to day leadership of
Cooper Energy. He is the leader of the
management team. Mr Maxwell is also chair
of the HSEC Committee (a management
committee, not a Board committee).
Ms Donaghey brings over 30 years’
experience in the energy sector including
technical, commercial and executive roles in
EnergyAustralia, Woodside Energy and
BHP Petroleum.
Ms Donaghey’s experience includes
non-executive director roles at Imdex Ltd,
an ASX-listed provider of drilling fluids and
downhole instrumentation: St Barbara Ltd,
a gold explorer and producer and the
Australian Renewable Energy Agency. She
has performed extensive committee roles
in these appointments, serving on audit
and compliance, risk and audit, technical
and regulatory, remuneration and health
and safety committees.
Current and other directorships in the
last 3 years
Ms Donaghey is a Non-executive Director
of Australian Energy Market Operator
(AEMO) (since 2017), Ms Donaghey is a
former Director of Imdex Ltd (2009 - 2016),
St Barbara Limited (2011 - 2014) and
Australian Renewable Energy Agency
(2012 - 2014)
Special responsibilities
Ms Donaghey does not currently hold any
Committee roles.
38
Non-Executive Director
Mr Hector M. Gordon B.Sc. (Hons). FAICD
Appointed 24 June 2017
Executive Director
26 June 2012 – 23 June 2017
Independent
Non-Executive Director
Mr Jeffrey W. Schneider B.Com
Appointed 12 October 2011
Independent
Non-Executive Director
Ms Alice J. M. Williams
B.Com FAICD, FCPA, CFA
Appointed 28 August 2013
Experience and expertise
Experience and expertise
Experience and expertise
Mr Schneider has over 30 years of experience
in senior management roles in the oil and gas
industry, including 24 years with Woodside
Petroleum Limited. He has extensive corporate
governance and board experience as both a
non-executive director and chairman in
resources companies.
Current and other directorships in the
last 3 years
Mr Schneider is a former Director of Comet
Ridge Limited ASX: COI (2003 – 2014).
Special responsibilities
Mr Schneider is Chairman of the Remuneration
and Nomination Committee and a member of
both the Risk and Sustainability Committee and
the Audit Committee.
Mr Gordon is a very successful geologist with
over 40 years of experience in the petroleum
industry. 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. Mr. Gordon’s
previous employers also include Santos
Limited, AGL Petroleum, TMOC Resources,
Esso Australia and Delhi Petroleum Pty Ltd.
Current and other directorships in the
last 3 years
Mr Gordon is a Director of Bass Oil Limited
ASX: BAS (since 2014) and various wholly
owned subsidiaries of Cooper Energy Limited.
Special responsibilities
Mr Gordon is the Chairman of the Risk and
Sustainability Committee and a member of the
Audit Committee.
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, Telstra Sale Company, V/Line
Passenger Corporation, State Trustees,
Western Health and the Australian Accounting
Standards Board.
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, Victorian Funds
Management Corporation (since 2008),
Barristers Chambers Ltd (since 2015), the
Foreign Investment Review Board (since
2015), Defence Health (since 2010) and not
for profit Tobacco Free Portfolios (since 2018).
Ms Williams is a former council member
of the Cancer Council of Victoria and former
Non-executive Director of Guild Group and
Port of Melbourne Corporation.
Special responsibilities
Ms Williams is the Chairman of the Audit
Committee and a member of both the Risk and
Sustainability Committee and the Remuneration
and Nomination Committee.
39
Executive Management Team
Managing Director
David Maxwell M. Tech FAICD
General Manager,
Development
Duncan Clegg
PhD – Soil Mechanics, BSc Engineering
Company Secretary
and Legal Counsel
Alison Evans B.A., LLB
General Manager,
Commercial and
Business Development
Eddy Glavas B.Acc CPA, MBA
Ms Evans was appointed to the
position of Company Secretary and
Legal Counsel on 25 February
2013.
Ms Evans is an experienced
company secretary and corporate
legal counsel with extensive
knowledge of corporate and
commercial law in the resources
and energy sectors. Ms Evans has
been Company Secretary and/or
Legal Counsel in a number of
minerals and energy companies
including Centrex Metals, GTL
Energy and AGL. Ms Evans’ public
company experience is supported
by her work at leading corporate
law firms.
Mr Glavas joined Cooper Energy
in August 2014 with more
than 16 years’ experience in
business development, finance,
commercial, portfolio management
and strategy, including 12 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&NT, where
Mr Glavas was a member of the
leadership team that managed
a large asset portfolio; corporate
roles in strategy and planning;
and operational, commercial and
finance roles for Santos’ Cooper
Basin assets.
Mr 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.
As Senior Vice President at QGC
- a BG Group business – he was
responsible for all commercial,
exploration, business development,
strategy and marketing activities.
He led BG Group’s entry into
Australia, its involvement in
the alliance with Queensland Gas
Company Limited and its
subsequent takeover by BG Group.
Mr Maxwell was previously
director of gas and marketing
with Woodside in Perth and a
member of Woodside’s executive
committee. He has served on a
number of industry association
boards, government advisory
groups and public company
boards and is a recipient of the
Australian Gas Association Silver
Flame Award for his contribution
to the gas industry.
Mr Clegg has extensive experience
in upstream and midstream
oil and gas development acquired
over 35 years, including senior
management positions at Shell
and Woodside. His experience
features leadership roles in the
North Sea, Africa and Malaysia,
the management of gas receiving
facilities and LNG plant
expansions at Bintulu (Malaysia)
and the North West Shelf and
FPSO, subsea and fixed platforms
developments.
Mr Clegg held several senior
executive positions at Woodside
including Director of the Australia
Business Unit, Director of the
Africa Business Unit and CEO
of the North West Shelf Venture.
Prior to joining Cooper Energy he
managed the development
and projects group at Coogee
Resources and worked as an
independant consultant on
a range of offshore oil and gas
project developments including
FLNG with Höegh LNG. Mr Clegg
was a board member of Verve
Energy from 2011 to 2013 and of
Matrix Composites Limited from
2014 to 2017.
40
General Manager,
Projects
Michael Jacobsen
B. Eng (Hons)
Mr Jacobsen has over 25 years
experience in upstream oil and
gas specialising in major capital
works projects and field
developments.
He has worked more than 10
years with engineering and
construction contractors and then
progressed to managing multi
discipline teams on major capital
projects for E&P companies.
Mr Jacobsen is the Project
Manager for the Sole GasProject
from the commencement of FEED.
General Manager,
Operations
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 20 years’ experience
in finance and accounting and
secretarial roles, including 18
years in publicly listed entities,
principally in group finance and
secreterial roles in the resources
and media sectors. This has
included the role of 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, culminating in
performance of the role of 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. Following the
takeover, he was COO at Bight
Petroleum, a privately held
independent exploration company
and was a Director of Barker
Wentworth, a specialist oil and gas
consulting company.
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
also 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.
41
Key Performance Indicators
Operational
Production
12 months
to 30 June
MMboe
Proved and probable reserves
MMboe
Wells drilled
number
Exploration wells spudded
number
2010
2011
2012
2013
2014
2015
2016
2017
2018
0.47
2.00
4
4
0.41
2.47
12
6
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
Reserve replacement ratio1
percent
11%
134%
-113%
98%
71%
333%
18%
768% 2,380%
4.7
9.1
21.0
8.4
61.5
13.2
53.4
22.5
37.0
Financial
Sales revenue
Other revenue
EBITDA
Profit before tax
Profit after tax / (loss)
$ million
40.0
39.1
59.6
53.4
72.3
39.1
27.4
39.1
$ million
$ million
$ million
$ million
4.3
8.0
7.2
1.2
5.1
(6.0)
(5.5)
(10.3)
2.3
22.3
18.3
2.8
1.9
0.9
36.9
(58.4)
(37.4)
1.6
1.9
31.2
(18.8)
(26.0)
(7.0)
1.3
22.0
(63.5)
(34.8)
(12.3)
67.5
4.9
49.9
31.0
27.0
Cash and term deposits
$ million
92.5
72.4
Other financial assets
Working capital
Accumulated profit
$ million
$ million
$ million
Cumulative franking credits
$ million
-
95.4
24.4
25.7
-
79.5
14.1
31.4
47.9
20.2
51.7
23.8
39.0
49.1
26.0
41.2
39.4
49.8
147.5
236.9
1.9
1.0
0.7
42.6
43.0
44.2
84.0
154.0
45.7
(17.7)
(52.6)
(64.9)
(37.9)
38.7
43.7
42.9
42.9
42.9
Shareholders equity
$ million
125.1
114.9
136.9
137.2
167.8
103.9
91.6
285.0
443.9
Earnings per share
cents
0.4
(3.5)
2.8
0.4
6.4
(19.2)
(10.1)
(1.8)
1.8
Return on shareholders funds
percent
1.0%
-8.6%
6.7%
0.9%
14.4% -46.7% (-38.0)%
-6.5%
7.4%
Total shareholder return
percent
(17.8)% (2.7)%
25.0% (16.7)%
34.7% (51.5)% (12.2)%
72.7
6.0%
Average oil price
A$/bbl
87.02
95.42
114.63
112.31
124.08
85.48
60.75
61.89
99.61
Capital as at 30 June
Share price
Issued shares
$ per share
0.37
0.36
0.45
0.375
0.505
0.245
0.215
0.38
0.385
million
292.6
292.6
327.3
329.1
329.2
331.9
435.2
1,140.2 1,601.1
Market capitalisation
$ million
108.3
105.3
147.3
123.4
166.3
81.4
93.6
433.3
616.4
Shareholders
number
6,537
5,573
5,485
5,284
5,122
5,103
4,931
6,292
6,622
1. Reserve replacement ratio calculated by net IP reserve addition/production.
42
Cooper Energy Limited and its controlled entities
Financial Report
For the year ended 30 June 2018
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 Financial Statements
1 Corporate information
2
3
4
5
Summary of significant accounting policies
Segment reporting
Revenues and expenses
Income tax
6 Discontinued operations and assets held for sale
7 Earnings per share
8 Cash and cash equivalents and term deposits
9
Trade and other receivables
10 Prepayments
11 Equity instruments
12 Oil and gas assets
13 Impairment
14 Property, plant and equipment
15 Exploration and evaluation
16 Trade and other payables
17 Provisions
18 Interests in joint arrangements
19 Contributed equity and reserves
20 Financial risk management objectives and policies
21 Hedge accounting
22 Commitments and contingencies
23 Interests in joint arrangements
24 Related parties
25 Share based payment plans
26 Auditors remuneration
27 Parent entity information
28 Events after the reporting period
Directors’ Declaration
Independent Audit Report
Auditors’ Independence Declaration
Abbreviations and terms
44
54
56
74
75
76
77
78
78
91
94
95
97
98
99
100
100
100
101
101
101
102
102
102
104
104
106
110
111
112
112
114
116
116
116
117
118
126
127
Corporate Directory Inside back cover
4343
Operating and Financial Review
For the year ended 30 June 2018
Summary Overview
The Company’s financial accounts for the twelve months to 30 June (“the year” “2018 financial year” or “FY18”) are the first to report a full
twelve-month performance since the Victorian gas asset acquisition completed in the prior year.
Significant changes in the entity’s structure
Two features of the results are particularly noteworthy: the scale of growth in the Company and its financial and operating results; and the value
added by the technical, commercial and financing activities undertaken during the year. The most significant example of the latter was the Final
Investment Decision (“FID”) for the Sole Gas Project on 29 August. Gas contracting, workover results and project performance were other sources
of significant value creation during FY18.
Cooper Energy’s position at year end was one from which further growth in scale and value is expected to be achieved. The Sole Gas Project has
advanced consistent with schedule and budget; new gas contracts are in the midst of negotiation; and planning has commenced on a range of
development, appraisal and exploration projects expected to be undertaken within 18 to 24 months.
Operations
Cooper Energy generates revenue from the supply of gas to south-east Australia and oil production in the Cooper Basin. The Company’s current
operations and interests include:
• offshore gas and gas liquids production in the Otway Basin, Victoria, from the Casino Henry and Minerva Gas Projects;
• the Sole Gas Project under development in the offshore Gippsland Basin;
• the Manta gas and liquids resource in the offshore Gippsland Basin;
• onshore oil production and exploration from the western flank of the Cooper Basin;
• gas exploration in the offshore and onshore Otway Basin; and
• offshore gas exploration in the Gippsland Basin.
The Company is the Operator for offshore gas production and exploration in the Otway Basin and offshore gas exploration and development in the
Gippsland Basin.
Reserves and contingent resources
Proved and probable reserves at 30 June were 52.4 million boe (barrels of oil equivalent) compared with 11.7 million boe at the beginning of the
period. Contingent resources (2C) were 23.6 million boe compared with 77.6 million boe.
The reclassification of 42.7 million boe of gas in the Sole gas field from contingent resources (2C) to proved and probable (2P) reserves was the
major factor in the movement in reserves and resources.
Proved and probable reserves comprise 309.5 PJ of gas and 1.9 million barrels of oil.
Workforce
At 30 June 2018 the Company had 38.9 full time equivalent (FTE) employees and 62.1 FTE contractors compared with 26.9 FTE employees
and 14.1 FTE contractors at 30 June 2017. The increase in employee numbers is consistent with the development of the Company’s scale
and responsibilities. Contractor numbers increased due to resourcing for the Sole Gas Project, in particular the offshore drilling campaign that
commenced in March 2018.
Health Safety Environment and Community
The Company submitted, and received regulatory acceptance for environmental management plans and safety cases in respect of Victorian gas
assets acquired in January 2017 for which the Company now has Operator responsibility. These include the Casino Henry Gas Project, Sole Gas
Project and VIC/P44.
Zero recordable cases or reportable environmental incidents occurred within Cooper Energy operations during the 12 months to 30 June 2018.
No lost time incidents were recorded and there were two restricted work case incidents.
Production
Production for the year of 1.49 million boe compares to 0.97 million boe in FY17.
The movement against the previous year incorporates:
• the contribution of a full year’s gas production of 7.04 PJ from Otway Basin gas assets, which contributed six month’s production of 4.03 PJ
to the prior year results. These assets also contributed 6.2 thousand barrels of condensate compared to 3.7 thousand barrels for the 6-month
period from acquisition in FY17;
• increased crude oil production from the Cooper Basin. Oil produced by the Company’s interests in the western flank of the Cooper Basin was
0.27 million barrels, 8% higher than the previous year’s production of 0.25 million barrels; and
• offset by oil production of 25.9 thousand barrels in FY17 from Indonesian assets divested in that year.
44
Operating and Financial Review
For the year ended 30 June 2018
Operations continued
Commercial
The Company’s strategy for the creation of shareholder value involves the establishment and operation of a portfolio style gas business to address
supply opportunities in south-east Australia, supported by low cost oil operations.
Commercial activities in the period from 2012 to 2017 were directed towards building an asset portfolio capable of generating value from the
supply opportunities foreseen. With a core portfolio in place by 2017, the focus of commercial activities in 2018 shifted to gas contracting and the
acquisition of assets which add value to the Company or to other assets already held.
In December 2017 the Company agreed a new gas supply contract with Origin Energy Limited for the supply of gas from Casino Henry for the
period 1 March 2018 to 31 December 2018. The contract is the first new sales agreement for the project since it commenced supply in 2006 and
has realigned prices for gas supplied from Casino Henry to current market levels. Negotiation of new sales agreements to operate from 1 January
2019 are progressing.
Gas from Casino Henry is processed at the Iona Gas Plant under an agreement with Lochard Energy with matching duration to the gas supply
contract. In addition, the signing of an agreement with BHP Petroleum during the year to acquire the Minerva Gas Plant provides the Casino
Henry joint venture with a competitive longer-term alternative supply option which also holds strategic value as a hub for broader Otway Basin gas
development.
Exploration and development
Otway Basin, offshore
The Company holds offshore and onshore interests in the Otway Basin.
Offshore interests comprise:
a) a 50% interest in, and Operatorship of, the producing Casino Henry Netherby (“Casino Henry”) Production Licences (VIC/L24 and VIC/L30);
b) a 50% interest in, and Operatorship of, Retention Licences VIC/RL11 and VIC/RL12;
c) a 50% interest in, and Operatorship of, Exploration Permit VIC/P44; and
d) a 10% interest in the Minerva Gas Project comprising the offshore licence VIC/L22 and the Minerva Gas Plant, onshore Victoria.
Exploration
Exploration activities in relation to VIC/P44 included a review of exploration potential. Processing of the VIC/P44 3D seismic survey was conducted
and seismic reprocessing completed and integrated into other exploration studies. The work identified several exploration prospects, located in
good proximity to pipelines, considered to hold potential to be economic gas discoveries. Work is proceeding on the selection of up to 2 targets for
drilling in an offshore drilling campaign proposed for FY20.
Development
The Casino Henry Joint Venture conducted a workover of the Casino-5 well, which had been shut-in since May 2017. The workover was
successful and Casino-5 returned to service in April 2018 with daily gross production from Casino Henry increasing from 26.7 TJ/day averaged in
the March quarter to average 33.2 TJ/day for the balance of the financial year.
Planning and analysis commenced for the drilling of a development well to access the undeveloped reserves of the Henry field. It is expected the
well, most likely a sidetrack of the existing Henry-2 well, will be drilled in the December quarter 2019, subject to joint venture approval and rig
availability.
Otway Basin, onshore
Onshore Otway Basin interests are located in the states of South Australia and Victoria. In South Australia, the Company holds a 30% interest
in each of PEL 494 and PRL 32, the balancing interests and operatorship of both blocks are held by Beach Energy Limited. The licences are
adjacent to PPL 62 which contains the Haselgrove gas discovery announced by Beach Energy Limited during the year.
Activity in the Victorian onshore Otway Basin is currently in suspension pursuant to the moratorium imposed by the Victorian state government on
onshore exploration until June 2020. Interests held in the Victorian Otway Basin include PEP 168 (50%), PEP 150 (currently 20%, increasing to
50% pending government ratification) and PEP 171 (currently 25% increasing to 100% on pending government ratification).
45
Operating and Financial Review
For the year ended 30 June 2018
Operations continued
Gippsland Basin
Commercialisation of the Company’s gas resources in the Gippsland Basin is a principal element of the Company’s growth strategy.
The Company’s interests in the region comprise:
a) a 100% interest in, and Operatorship of, Production Licence VIC/L32 which holds the Sole gas field;
b) a 100 % interest in, and Operatorship of, Retention Licences VIC/RL13, VIC/RL14 and VIC/RL15, which hold the Manta gas field. Manta
is assessed to contain contingent resources (2C) of 106 PJ1 of gas and 3.2 MMbbl of liquids as well as hydrocarbon potential in deeper
reservoirs. The retention leases also hold legacy oil infrastructure associated with the disused BMG oil project;
c) a 100% interest in, and Operatorship of, Retention Licence VIC/RL22 which contains the largely depleted and shut-in Patricia-Baleen
gas field, and infrastructure offering connection to the Orbost Gas Plant; and
d) a 100% interest in Exploration Permit VIC/P72 awarded in May 2018.
The Company is pursuing a two-phase development program of its Gippsland gas resources involving development of Sole to supply gas from
2019 and a subsequent development of Manta.
Sole Gas Project
The Sole Gas Project is being undertaken to develop the Sole gas field, offshore Victoria, for supply to commence mid-2019.
The project has a budget total capital cost of $605 million, comprising a $355 million offshore development to be conducted by Cooper Energy
and the $250 million upgrade of the existing Orbost Gas Plant by APA Group. Sole is being developed by the drilling and completion of two
production wells, installation and connection of subsea wellheads and infrastructure to the Orbost Gas Plant via 65 kilometres of pipe, a control
umbilical and horizontally directional drilled (HDD) shore crossing.
Offshore project FID occurred on 29 August 2017. At 30 June the offshore project was proceeding within schedule and budget having
reached 56% complete with incurred capital expenditure by Cooper Energy of $189 million. Project milestones completed include the twin
horizontal directional drilled shore crossing for the pipeline and umbilical and, after year end, the drilling, and completion of the Sole-3 and
Sole-4 production wells, inclusive of subsea wellhead installation. Welding of the pipeline is underway and advancing towards readiness for the
installation commencement in October 2018. The umbilical has been manufactured in the UK and is having end fittings applied prior to testing.
Installation of the umbilical is expected to be performed between November 2018 and January 2019.
The completion of the production wells in August 2018 marked a major milestone for the offshore project, establishing well production
performance exceeding plant design requirements and gas composition and reservoir characteristics in line with Sole-2 and expectations.
Manta Gas Project
Development of the Manta gas and liquids field is being pursued as a second phase Gippsland gas development, utilising economies available
through coordination with the Sole Gas Project.
A formal business case conducted in 2015 found that commercialisation of the gas field could be feasible. Appraisal of the field’s contingent
resources is considered necessary for confirmation of the assessed contingent resource. It is intended that this well, Manta-3, will also test the
potential of a prospective resource in deeper reservoirs. The results of Manta-3 will inform a development decision on the field and the final firm
development plan. Current expectations are that Manta-3 will be drilled in the offshore drilling campaign being planned for FY20.
Based on the current contingent resource, the Manta development concept is expected to involve subsea wellheads for the production of gas and
gas liquids through connection to the Orbost Gas Plant by either a direct pipeline or via connection to the Patricia-Baleen gas field and pipeline.
Cooper Basin
Interests in the Cooper Basin include a 25% interest in the oil producing PEL 92 Joint Venture (PRL’s 85 – 104) and a 30% interest in the PPL
207 Joint Venture and their associated petroleum retention licences. The Company participated in two exploration wells during the period, one by
each joint venture, which were both plugged and abandoned after failing to encounter significant hydrocarbons.
The Company also holds interests in exploration licences in the northern Cooper Basin.
There were no other exploration or development activities of significance in the Company’s Cooper Basin acreage during the year.
1 Cooper Energy announced contingent and prospective resource attributable to Manta on 16 July 2015. Cooper Energy is not aware of any new
information or data that materially affects the information provided in those releases and all material assumptions and technical parameters
underpinning the assessment provided in the announcement continues to apply.
46
Operating and Financial Review
For the year ended 30 June 2018
Financial Performance
Cooper Energy recorded a statutory profit after tax of $27.0 million for the financial year which compares with the loss after tax of $12.3 million
recorded in the 2017 financial year. The 2018 financial year profit included a number of items which affected the result by a total of $17.2 million.
These items comprise:
• a gain on sale of the Orbost Gas Plant of $21.9 million;
• a non-cash restoration expense of $4.9 million resulting from a remeasurement of the Patricia Baleen Field rehabilitation provision;
• impairment losses recognised in respect of the Group’s Cooper Basin northern licenses of $0.5 million net of tax impacts;
• a gain on the movement in the consideration receivable from the sale in the prior year of Sukananti of $0.5 million;
• a gain on the derecognition of the Group’s investment in an associate of $0.4 million; and
• a loss on the movement in the Hammamet exit provision of $0.2 million.
Financial Performance
Sales volume
Sales revenue
Gross profit
Gross profit / Sales revenue
Operating cash flow
Cash, other financial assets and investments
Reported NPAT/(loss) after tax
Underlying NPAT/(loss) after tax
Underlying profit/(loss) before tax
Underlying EBITDA*
MMboe
$ million
$ million
%
$ million
$ million
$ million
$ million
$ million
$ million
FY18
1.482
67.5
29.0
43.0
22.2
259.3
27.0
9.8
14.0
32.6
FY17
0.951
39.1
16.6
42.5
4.1
148.2
(12.3)
(8.7)
(5.8)
5.3
Change
0.531
28.4
12.4
0.5
18.1
111.1
39.3
18.5
19.8
27.3
%
56%
73%
75%
1%
441%
75%
320%
213%
341%
515%
* Earnings before interest, tax, depreciation and amortisation
Note the comparative numbers in the table above include discontinued operations.
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.
Calculation of underlying NPAT / (loss) by adjusting for items unrelated to the underlying operating performance is considered to provide
meaningful comparison of results between periods. Underlying NPAT / (loss) and underlying EBITDA are not defined measures under
International Financial Reporting Standards and are not audited. Reconciliations of NPAT / (loss), Underlying NPAT / (loss), Underlying EBITDA
and other measures included in this report to the Financial Statements are included at the end of this review.
The underlying profit after tax (exclusive of the items noted above) was $9.8 million, compared with an underlying loss after tax of $8.7 million
in the 2017 financial year. The factors which contributed to the movement between the periods were:
• higher gas sales revenue of $21.9 million as a result of a full year of revenue from the assets acquired during the 2017 financial year;
• higher oil sales revenue of $6.5 million as a result of increased oil price realised throughout the period and increased volumes, partially offset
by the sale of the Company’s Indonesian producing assets in the 2017 financial year;
• higher interest revenue of $2.8 million as a result of higher cash balances;
• higher production costs of $6.2 million as a result of the Victorian gas assets and increased Cooper Basin production;
• higher amortisation costs of $9.7 million, mainly due to amortisation on gas assets acquired;
• lower administration and other costs of $3.8 million, mainly relating to higher cost recoveries associated with increased activities on
operated projects;
• higher non-cash finance costs and restoration expenses of $0.2 million, as a result of accretion relating to rehabilitation provisions associated
with the assets acquired during the 2017 financial year; and
• higher tax expense of $1.2 million mainly in respect of PRRT relating to the Company’s producing gas assets.
47
Operating and Financial Review
For the year ended 30 June 2018
Financial Position
Financial Position
Total assets
Total liabilities
Total equity
Assets
$ million
$ million
$ million
FY18
816.8
372.9
443.9
FY17
492.6
207.6
285.0
Change
324.2
165.3
158.9
%
66%
80%
56%
Total assets increased by $324.2 million from $492.6 million to $816.8 million.
At 30 June the Company held cash and deposit balances of $236.9 million, other financial assets of $20.1 million, investments of $2.2 million
and drawn debt of $125.9 million.
Cash and deposit balances increased by $89.4 million over the period as summarised in the chart below. Operating activities produced
$22.2 million of cash flows, including:
• cash generated from operations of $46.1 million;
• interest revenue of $3.8 million;
• general administration costs of $8.6 million;
• restoration costs of $12.4 million;
• petroleum resource rent tax (“PRRT”) payments of $6.7 million.
Financing and investing cash flows included:
• net proceeds from equity issues of $127.2 million;
• debt drawdowns of $113.6 million (net of costs of $12.3 million);
• restoration proceeds from exited parties of $48.1 million;
• interest payments of $4.6 million;
• exploration and development costs of $198.5 million;
• acquisitions of oil and gas assets of $21.0 million consisting of contingent consideration of $20.0 million paid to Santos Limited on the
FID decision on the Sole Gas Project and $1.0 million in respect of the Minerva Plant acquisition;
• receipts from the disposal of producing assets of $0.7 million;
• receipts from sale of the Orbost Gas Plant of $41.9 million; and
• transfers of cash to escrow accounts of $40.2 million.
48
Operating and Financial Review
For the year ended 30 June 2018
Financial Position continued
$ million
Total cash,
other financial assets
and investments
148.2
-4.6
+48.1
+113.6
-198.5
Total cash,
other financial
assets and
investments
259.3
+127.2
-21.0
+0.7
+41.9
-40.2
22.4
Other financial
assets and
investments
Other financial
assets and
investments
0.7
-8.6
-12.4
+46.1
+3.8
-6.7
Cash &
deposits
147.5
169.7
236.9
Cash &
deposits
Operating
+22.2
Other
+67.2
June -17 Operations General
Admin
Restoration
costs
PRRT Interest Cash after
operating
cash flows
Net debt
draw-
downs
Net
proceeds
from
equity
issues
Restoration
proceeds
Interest
payments
E & D Acquisitions
of oil & gas
assets
Transfer
to escrow
June-18
Receipts
from
disposal of
producing
asset
Receipts
from
disposal
of PPE
Exploration and evaluation assets decreased $124.6 million from $223.3 million to $98.7 million as a result of transferring the carrying amount of
the Sole asset from exploration to oil and gas properties on FID partially offset by capital expenditure incurred on exploration activities.
Oil and gas assets increased by $325.2 million from $69.4 million to $394.6 million mainly as a result of transferring the Sole asset on FID (as
mentioned above) and capital expenditure incurred on the project after FID partially offset by amortisation charges.
Total Liabilities
Total liabilities increased by $165.3 million from $207.6 million to $372.9 million.
Provisions increased by $61.5 million from $119.0 million to $180.5 million attributable to the assumption of increased rehabilitation provisions
for BMG on settling with exited parties and the recognition of provisions associated with the drilling of Sole-3 and Sole-4.
Interest bearing loans and borrowings increased to $116.9 million from a nil balance in the 2017 financial year. This represents the drawdowns
under the reserve-based lending (RBL) facility of $125.9 million offset by associated capitalised transaction costs of $8.9 million.
Total Equity
Total equity has increased by $158.9 million from $285.0 million to $443.9 million. In comparing equity at June 2018 to June 2017 the key
movements were:
• higher contributed equity of $128.7 million due to shares issued from equity raisings and shares issued on vesting of performance rights during
the period;
• higher reserves of $3.2 million mainly due to the issue of equity incentives to employees partially offset by fair value movements in the
Company’s oil price options and interest rate swaps for which cash flow hedge relationships apply; and
• lower accumulated losses of $27.0 million due to the reported profit for the period.
49
Operating and Financial Review
For the year ended 30 June 2018
Business Strategies and Prospects
As noted under ‘Commercial’ above, the core element of the Company’s strategy for the generation of shareholder wealth is the operation of a
portfolio of gas assets with superior competitiveness in the supply of gas to south-east Australia. The foundation for this strategy’s success is value-
adding acquisition, discovery, development, contracting and supply of gas.
At 30 June 2018, Cooper Energy occupied a position from which growth in shareholder value is expected.
The passage of the Sole Gas Project has the Company on schedule to increase gas sales from 6 PJ per annum (“p.a.”) to approximately 30 PJ
p.a. within 2 years. The Company holds uncontracted 2P gas reserves of some 127 PJ, which are competitively located and will be marketed into
south-east Australia where forecast demand is expected to exceed local production for the foreseeable future.
The Company’s portfolio holds the potential to add more gas reserves through commercialisation of contingent resources present in the Manta
gas field and the exploration drilling of prospects identified in the offshore and onshore Otway basins. Cooper Basin oil operations are expected to
continue to generate cash from low cost, high margin oil production.
Acquisition opportunities will be assessed for their capacity to generate value for shareholders, subject to the Company’s stated key investment
criteria:
1) the assets are cost competitive;
2) there is a foreseeable pathway to commercialisation within 5 years; and
3) the opportunity offers the potential for value creation; whether that be an incremental increase to the value of the assets through the
application of Cooper Energy’s capabilities and/or an incremental increase to the value of Cooper Energy’s portfolio arising from integration of
the assets.
Outlook
FY19 is expected to be a year of consolidation as the Sole Gas Project is completed and preparations made for an offshore drilling campaign to
commence in the December quarter 2019, subject to rig availability.
Production of 1.4 million boe is expected from existing operations, comprising 6 PJ of gas from the Otway Basin and approximately 230,000
barrels of oil. Production arising from Sole commissioning, which is expected to commence in the final quarter of FY19, has not been included in
firm guidance.
Commercial activities will include concluding gas sales agreements for the supply of Casino Henry gas for the 2019 calendar year and contracting
further tranches of Sole gas. Whereas previous marketing of Sole gas was conducted to secure long-term agreements to support project financing,
the strategy for this new round of Sole gas contracting is likely to be directed to shorter term contracts and positions which optimise value for
shareholders for gas reserves from anticipated market conditions.
The completion of the Sole Gas Project will be the major development project for FY19, accounting for 79% of incurred capital expenditure
forecast for the period. It is anticipated that pipeline and umbilical connection of the Sole production wells will be completed in January 2019.
Commissioning involving Sole gas to the plant is expected from April 2019. In the Otway Basin, work is to be conducted on maintenance and
repairs to the Casino Henry umbilical, expansion readiness and preparation for the Henry-2 sidetrack development well.
The offshore drilling campaign being prepared for FY20 comprises up to 4 wells, 3 of which are expected to involve exploration for new gas
reserves: the Manta Deep prospect and, subject to joint venture approval, 2 wells in VIC/P44. Planning for this campaign, including joint venture
selection of targets for the exploration drilling in VIC/P44 is expected to occupy the major share of the Company’s exploration and subsurface
efforts for the year.
At this stage Cooper Energy expects to participate in one well during FY19, an exploration well planned for PEL-494 in the South Australian
onshore Otway Basin. The well has the sandstones of the Pretty Hill Formation and the deeper Sawpit Sandstone successfully tested at the
Haselgrove-3 well as its primary targets and will be part funded by a $6.89 million PACE grant from the South Australian government.
Abandonment activities are planned in the Gippsland Basin, commencing with the abandonment of Sole-2 and then on legacy oil infrastructure at
Basker Manta Gummy (“BMG”) in VIC RL/13, RL/14 and RL/15.
50
Operating and Financial Review
For the year ended 30 June 2018
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 the Company had cash, deposits, financial assets and investments of $259.3 million and drawn debt of $125.9 million2. 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, $224.0 million
is available, of which $98.1 million remains undrawn at 30 June 2018. The Company has additional liquidity of approximately $15 million through
a working capital facility to be used for general business purposes, of which $0.9 million has been utilised in respect of bank guarantees with the
remaining balance undrawn. Further information is detailed in Notes 2, 8 and 18 of the Financial Statements.
The Company continues to assess value accretive funding options as it pursues near term growth opportunities.
Risk Management
The Company manages risks in accordance with its risk management policy with the objective of ensuring all risks inherent in oil and gas
exploration and production activities are identified, measured and then managed or kept as low as reasonably practicable. The Management
Team perform risk assessments on a regular basis and a summary is reported to the Risk and Sustainability Committee (previously The Audit and
Risk Committee). The Committee approves and oversees an internal audit program undertaken internally and/or in conjunction with appropriate
external industry or field specialists.
Key risks which may materially impact the execution and achievement of the business strategies and prospects for Cooper Energy are
summarised below and are risks largely inherent in the oil and gas industry. This should not be taken to be a complete or exhaustive list of risks
nor are risks disclosed in any particular order. Many of the risks are outside the control of the Company and its officers.
Appropriate policies and procedures are continually being developed and updated to manage these risks.
Risk
Exploration
Development and
Production
Regulatory
Description
Exploration is a speculative activity with an associated risk of discovery to find any 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 that all major 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.
Cooper Energy has a project risk management and reporting system to monitor the progress and performance of
material projects and is subject to regular review by senior management and the Board. All major development and
investment decisions are subjected to assurance reviews which includes experts and contractors where
appropriate.
Cooper Energy operates in a highly regulated environment. Cooper Energy complies with the regulatory authorities
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.
2 Shown as $116.9 million on the balance sheet, net of prepaid transaction costs.
51
Operating and Financial Review
For the year ended 30 June 2018
Risk Management continued
Risk
Market
Description
The oil market and Australian domestic gas market are subject to the fluctuations of supply and demand and price.
To the extent that future actions of third parties contribute to demand destruction or there is an expansion of
alternative supply sources, there is a risk that this may have a material adverse effect on price for the oil and gas
produced and the Company’s business, results of operations and financial condition.
Cooper Energy regularly 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.
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.
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 and an HSEC management system to ensure safe and sustainable operations.
The ability of the Company to achieve its stated objectives will depend on the performance of the counterparties
under various agreements (including joint venture arrangements) it has entered into. If any counterparties do not
meet their obligations under the respective agreements, this may impact on operations, business and financial
conditions.
Cooper Energy monitors performance across material contracts against contractual obligations to minimise
counterparty risk and seeks to include terms in agreements which mitigate such risks.
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.
Reserve management is consistent with the definitions and guidelines in the Society of Petroleum Engineers 2007
Petroleum Resources Management Systems. The assessment of Reserves and Resources is also subject to
independent review from time to time.
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.
Cooper Energy has a comprehensive approach to the management of risks associated with health, safety,
environment and community which includes standards for asset reliability and integrity, as well as technical and
operational competency requirements.
Counterparties
Reserves
Environmental
52
Operating and Financial Review
For the year ended 30 June 2018
Risk Management continued
Risk
Funding
Description
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 condition 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.
Abandonment liabilities 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 the construction of the facility and conducts a review on an
annual basis. Any changes to the estimates of the provisions for restoration are recognised in line with accounting
standards.
Reconciliations for net profit/(loss) to Underlying net profit/(loss) and Underlying EBITDA
Reconciliation to Underlying profit/(loss)
Net profit/(loss) after income tax
Adjusted for:
Impairment of discontinued operations & loss on sale
Gain on derecognition of investment in associate
Exit provision
Impairment of exploration and evaluation
Restoration expense
Gain on sale of subsidiary
Gain on movement of consideration receivable
Tax impact of above changes
Underlying profit/(loss)
Reconciliation to Underlying EBITDA*
Underlying profit/(loss)
Add back:
Interest revenue
Accretion expense
Tax expense/(benefit)
Depreciation
Amortisation
Underlying EBITDA*
* Earnings before interest, tax, depreciation and amortisation
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
FY18
27.0
-
(0.4)
0.2
0.7
4.9
(21.9)
(0.5)
(0.2)
9.8
FY18
9.8
(4.0)
2.7
4.0
0.6
19.6
32.6
FY17
(12.3)
Change
39.3
1.0
-
4.0
-
-
(1.0)
(0.4)
(3.8)
0.7
4.9
%
320%
-100%
-100%
-95%
100%
100%
(1.4)
(20.5)
-1464%
-
-
(8.7)
(0.5)
(0.2)
18.5
FY17
(8.7)
Change
18.5
-100%
-100%
213%
%
213%
(1.6)
(2.4)
-150%
2.5
2.9
0.3
9.8
5.3
0.2
1.1
0.3
9.8
27.3
8%
38%
100%
100%
515%
53
Directors’ Statutory Report
For the year ended 30 June 2018
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 2018, and the independent auditor’s report thereon.
1. Directors
The Directors of the parent entity at any time during or since the end of the financial year are:
Mr John C. Conde AO
B.Sc. B.E(Hons), MBA
Chairman
Independent Non-Executive Director
Appointed 25 February 2013
Experience and expertise
Mr Conde has extensive experience in business and commerce and in chairing high profile business,
arts and sporting organisations.
Previous positions include Non-executive Director of BHP Billiton, Chairman of Pacific Power (the
Electricity Commission of NSW), 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) and the Sydney Symphony
Orchestra (2007 – 2015) and is a former Director of AFC Asian Cup (2015) (2012 – 2015).
Special Responsibilities
Mr Conde is Chairman of the Board of Directors. He is also a member of the Remuneration and
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 Ltd.
Special Responsibilities
Mr Maxwell is Managing Director and is responsible for the day to day leadership of Cooper Energy.
He is the leader of the management team. Mr Maxwell is also chair of the HSEC Committee (a
management committee, not a Board committee).
Experience and expertise
Mr Gordon is a very successful geologist with over 35 years of experience in the petroleum industry.
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. Mr. Gordon’s previous employers also include Santos Limited,
AGL Petroleum, TMOC Resources, Esso Australia and Delhi Petroleum Pty Ltd.
Current and other directorships in the last 3 years
Mr Gordon is a Director of Bass Oil Limited ASX: BAS (since 2014) and various wholly owned subsidiaries
of Cooper Energy Limited.
Special Responsibilities
Mr Gordon is the Chairman of the Risk and Sustainability Committee and a member of the
Audit Committee.
Mr David P. Maxwell
M.Tech, FAICD
Managing Director
Appointed 12 October 2011
Mr Hector M. Gordon
B.Sc. (Hons). FAICD
Executive Director
26 June 2012 – 23 June 2017
Non-Executive Director
Appointed 24 June 2017
54
Director’s Statutory Report
For the year ended 30 June 2018
1. Directors continued
Mr Jeffrey W. Schneider
B.Com
Independent Non-Executive Director
Appointed 12 October 2011
Ms Alice J. M. Williams
B.Com, FAICD, FCPA, CFA
Independent Non-Executive Director
Appointed 28 August 2013
Ms Elizabeth A. Donaghey
B.Sc., M.Sc.
Independent Non-Executive Director
Appointed 25 June 2018
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 is a former Director of Comet Ridge Limited ASX: COI (2003 – 2014).
Special Responsibilities
Mr Schneider is Chairman of the Remuneration and Nomination Committees and member of both the
Risk and Sustainability Committee and 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, Telstra Sale Company, V/Line Passenger
Corporation, State Trustees, Western Health and the Australian Accounting Standards Board.
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, Victorian Funds Management Corporation (since 2008), Barristers Chambers Ltd
(since 2015), the Foreign Investment Review Board (since 2015), Defence Health (since 2010) and
not for profit Tobacco Free Portfolios (since 2018). Ms Williams is a former council member of the
Cancer Council of Victoria and former Non-executive Director of Guild Group and Port of
Melbourne Corporation.
Special Responsibilities
Ms Williams is the Chairman of the Audit Committee and a member of both the Risk and Sustainability
Committee and the Remuneration and Nomination 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 Australian Energy Market Operator (AEMO) (since 2017),
Ms Donaghey is a former Director of Imdex Ltd (2009 - 2016), St Barbara Limited (2011 - 2014) and
Australian Renewable Energy Agency (2012 - 2014).
Special Responsibilities
Ms Donaghey does not currently hold any Committee roles.
2. Company secretary
Ms Alison Evans B.A., LLB was appointed to the position of Company Secretary and Legal Counsel on 25 February 2013. Ms Evans is an
experienced company secretary and corporate legal counsel with extensive knowledge of corporate and commercial law in the resources
and energy sectors. Ms Evans has been Company Secretary and/or Legal Counsel in a number of minerals and energy companies
including Centrex Metals, GTL Energy and AGL. Ms Evans’ public company experience is supported by her work at leading corporate
law firms.
55
Director’s Statutory Report
For the year ended 30 June 2018
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 are:
Director
Board Meetings
Mr J. Conde
Mr D. Maxwell
Mr H. Gordon
Mr J. Schneider
Ms A. Williams
Ms E. Donaghey
A
10
10
9
10
9
1
A = Number of meetings attended.
B
10
10
10
10
10
1
Audit & Risk
Committee
Meetings
Risk &
Sustainability
Meetings
Remuneration and
Nomination Committee
Meetings
A
-
-
4
4
4
-
B
-
-
4
4
4
-
A
-
-
3
3
2
-
B
-
-
3
3
3
-
A
3
-
-
3
2
-
B
3
-
-
3
3
-
B = Number of meetings held during the time the Director held office, or was a member of the committee, during the year
4. Remuneration Report
Information about the remuneration of the Company’s key management personnel for the financial year ended 30 June 2018 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 Remuneration
and Nomination Committee
Dear Shareholder
I am pleased to present our Remuneration Report for 2018 for which we will seek your support at the 2018 Annual General Meeting. The report is
designed to provide information regarding our remuneration framework and the outcomes for the reporting period.
Report context: 2018 Financial Year
The Company’s performance in the 12 months to 30 June 2018 is reported in the Operating and Financial Review of the Financial Report. This
performance, and that against the specific targets of the corporate scorecard provide the context of the Remuneration Report. Both the Operating
and Financial Review and the Remuneration Report documents a company that has grown and created value over the short and longer term
review periods and met or exceeded most of its benchmarks for 2018.
Significantly, certain milestones Cooper Energy set for itself in its corporate scorecard were achieved at the stretch level. This included growth in
production and revenue, progress of the Sole gas project and “enablers” such as cost management. In its first year as Operator of offshore gas
producing and development assets, the Cooper Energy team should be commended.
Market capitalisation of $433.4 million at 30 June 2017 was increased to $616.4 million at the conclusion of the year. For shareholders, a total
shareholder return of 6% was recorded over the reporting period. The performance of the company and its shares in the period since balance
date to the date of this report, while outside the scope of this remuneration report, is noteworthy retrospective affirmation of the strength of the
position attained by Cooper Energy at 30 June 2018.
As longer-term shareholders would be aware, the results achieved in 2018 have flowed from the disciplined application of a strategy by a stable
and committed management team over several years to create value from opportunities foreseen in the south-east Australian gas market.
This performance is congruent with the importance placed on long term and sustained value creation by the Board and the objectives of the
Company’s remuneration framework. The performance of the company, its position at 30 June and the stability of its management team indicates
that the company’s remuneration philosophy and framework have been effective in retaining, motivating and rewarding the existing team to deliver
value for you, its shareholders.
56
Director’s Statutory Report
For the year ended 30 June 2018
4. Remuneration Report continued
Developments
A significant development for the Company during the reporting period was the appointment of a new director. We were very pleased to welcome
Ms Donaghey onto the board on 25 June 2018. We look forward to the significant contribution her skills and experience will bring.
In terms of future developments in remuneration, we believe that the remuneration framework in place is working to deliver results and as such
we are not proposing significant changes. The only changes we will be making are to the LTIP to reflect the fact that Cooper Energy is now a larger
company albeit one from which further growth and scale is expected. In this regard, the Board has determined that the following changes will be
made to the LTIP Invitations for the 2019 financial year:
• The maximum award opportunity for the Managing Director will be reduced from a grant of 120% of his fixed annual remuneration to 100%;
and
• The performance period will remain for 3 years however there will no longer be any re-test at the end of that period.
We thank the Managing Director, the management team and their teams for their commitment and contribution over the year.
Yours sincerely
Mr Jeffrey Schneider
Chairman of the Remuneration and Nomination Committee
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
in place for key management personnel (KMP) for the reporting period.
The Remuneration 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.
Contents
4.1 Introduction
4.2 Key Management Personnel covered in this report
4.3 Remuneration governance
4.4 FY18 performance and Executive KMP outcomes
4.5 Nature of Executive KMP remuneration
4.6 Nature of Non-Executive Director remuneration
4.7 Statutory remuneration disclosures
Page
57
57
58
58
62
65
66
4.2 Key Management Personnel covered in this Report
In this Report, Key Management Personnel (KMP)are those individuals having the authority and responsibility for planning, directing and
controlling the activities of the Group, either directly or indirectly. They comprise:
• Non-executive Directors;
• The Managing Director; and
• the executives on the management team.
The Managing Director and other executives on the management 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
Mr J. Schneider
Ms A. Williams
Mr H. Gordon
Ms E. Donaghey
Position
Chairman
Non-executive Director
Non-executive Director
Non-executive Director
Non-executive Director
Dates
Full reporting period
Full reporting period
Full reporting period
Full reporting period
From 25 June 2018
57
Director’s Statutory Report
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4. Remuneration Report continued
4.2 Key Management Personnel covered in this Report continued
Executive KMP
Mr D. Maxwell
Mr A. Thomas
Mr E. Glavas
Ms A. Evans
Mr I. MacDougall
Ms V. Suttell
Mr D. Clegg
Mr M. Jacobsen
Position
Managing Director
General Manager Exploration & Subsurface
Dates
Full reporting period
Full reporting period
General Manager Commercial & Business Development
Full reporting period
Company Secretary and Legal Counsel
General Manager Operations
Chief Financial Officer
General Manager Development
General Manager Projects
Full reporting period
Full reporting period
Full reporting period
Full reporting period
Full reporting period
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 emphasises superior performance and
shareholder returns.
Cooper Energy’s approach towards remuneration aims to ensure that an appropriate balance is achieved among:
• maximising sustainable 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;
• achieve the most effective returns (employee productivity) for total employee spend; and
• ensure remuneration transparency and credibility for all employees and in particular for Executive KMP.
Cooper Energy’s policy is to pay fixed remuneration (base salary and superannuation) 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 Remuneration and Nomination Committee
The Company’s Remuneration and Nomination Committee (comprised during the reporting period of 3 Non-executive Directors, all of whom
are independent) makes recommendations to the Board regarding remuneration strategies and policies in relation to KMP. The Committee
assesses annually the nature and amount of Executive KMP remuneration by reference to relevant employment market conditions and third party
remuneration benchmark reports. The Committee determines remuneration arrangements in conjunction with the annual performance reviews of
the Executive KMP.
4.3.3 External remuneration advisers
From time to time, the Remuneration and Nomination Committee seeks and considers 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 Remuneration and Nomination 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.
4.4 FY18 performance and Executive KMP pay outcomes
4.4.1 Remuneration actually delivered to Executives in FY18 (not audited)
The Company believes that reporting remuneration actually delivered to 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.
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4. Remuneration Report continued
4.4 FY18 performance and Executive KMP pay outcomes continued
4.4.1 Remuneration actually delivered to Executives in FY18 (not audited) continued
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 4.7.3 and 4.7.4. The information in this section 4.4.1 is not audited.
The total benefits actually delivered during the reporting period and set out in the table below comprise several elements including:
• fixed remuneration being base salary and superannuation;
• STI cash payment made in October 2017 being the STIP awarded for performance during the prior period (FY17);
• the market value of shares issued in FY18 on the vesting of performance rights granted September 2014. The market value is taken to be the
share price at the date of issue of the shares;
• the value of other short term benefits including fringe benefits on accommodation, car parking and other benefits.
Name
Year
Fixed
Remuneration
$
STIP
$
LTIP
$
Other
$
Termination
Payments
$
Total
$
Executive Directors
Mr D. Maxwell
Mr H. Gordon1
Executives
Mr A. Thomas
Ms V. Suttell2
Ms A. Evans3
Mr I. MacDougall
Mr E. Glavas
Mr D. Clegg4
Mr M. Jacobsen5
Mr J. de Ross6
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
787,500
325,000
210,791
667,500
643,940
422,608
-
-
-
78,012
88,691
-
231,718
155,171
245,348
6,466
416,250
381,762
393,750
107,620
317,125
223,274
416,250
374,411
366,250
297,764
80,000
174,400
57,000
-
54,800
99,320
80,000
174,400
70,000
143,360
455,417
100,000
75,359
152,824
-
-
34,867
68,040
72,268
88,930
49,185
-
-
386,803
383,683
-
-
-
31,500
15,000
-
-
-
-
-
6,382
6,192
6,382
2,453
6,382
6,603
6,382
6,649
6,382
6,466
536
92
536
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,401,303
1,822,739
-
638,703
577,991
715,178
457,132
110,073
413,174
397,237
574,900
644,390
491,817
447,590
555,953
418,395
399,219
-
-
176,868
136,953
411,691
3,240
283,371
1,012,123
1. Mr Gordon was no longer an executive from 24 June 2017.
2. Ms Suttell commenced employment with the Company in an acting capacity part time (0.8 full time equivalent) on 18 January 2017. She
modified her hours to full time from 1 June 2017.
3. Ms Evans worked part time (0.8 full time equivalent for the period 1 February 2017 to 31 January 2018; and 0.9 full time equivalent for the
period 1 February 2018 to 30 June 2018) and accordingly her entitlements are prorated.
4. Mr Clegg commenced employment with the Company as General Manager Development on 1 May 2017. Prior to that time, he was engaged
by the Company as a contractor on a part time basis and was not considered KMP during this period. The amounts shown in the table above
include the total remuneration paid during the reporting period, including as a contractor.
5. Mr Jacobsen commenced employment with the Company and General Manager Projects on 1 July 2017.
6. Mr de Ross left employment on 9 December 2016. His termination payment included the payout of unused annual leave entitlements.
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4. Remuneration Report continued
4.4 FY18 performance and Executive KMP pay outcomes continued
4.4.1 Remuneration actually delivered to Executives in FY18 (not audited) continued
STI payments are generally made for performance over a 12 month period, however the acquisition of the Victorian gas assets from Santos
Limited during the 2017 financial year was an extraordinary event which transformed the Company and necessitated a re-set of the scorecard
performance measures as at 1 January 2017. As reported in the 2017 Annual Report, an interim STIP award was made to employees in January
2017. The STI payments made to Executive KMP detailed in the table above and paid in October 2017, relate only to performance during the
period 1 January 2017 to 30 June 2017 and comprise one half of the total STIP paid in respect of the second half of the 2017 financial year
(6 months). The STI payments made to Executive KMP detailed in the table above and paid during the 2017 financial year comprise STIP paid
in respect of the whole of 2016 financial year and the first half of the 2017 financial year (18 months).
4.4.2 Cooper Energy five-year performance
Operational
Annual production
Proved & Probable Reserves
TRCFR1
Financial
Sales revenue
Profit after tax
Earnings per share
Total shareholder return
Capital as at 30 June
Share price
Market capitalisation
MMboe
MMboe
events per hours worked
$ million
$ million
cents
percent
$ per share
$ million
1. Total Recordable Case Frequency Rate
4.4.3 STIP outcomes
2014
0.59
2.01
2.52
72.3
22.0
6.4
34.7
0.505
166.3
12 months to 30 June
2015
0.48
3.08
4.18
39.1
(63.5)
(19.2)
(51.5)
0.245
81.4
2016
0.46
3.00
0.00
27.4
(34.8)
(10.1)
(12.2)
0.215
93.6
2017
0.96
11.7
1.98
39.1
(12.3)
(1.8)
72.7
0.38
433.4
2018
1.49
52.4
4.07
67.5
27.0
1.8
6.0
0.39
616.4
The Scorecard results for the reporting period ranged between Target and Stretch. The final STIP results for the reporting period, in conjunction
with individual performance reviews will be determined in September and form the basis of individual STIP payments in October 2018.
Performance measures in
company scorecard
Weighting
Scorecard Result Comment
HSEC
20%
Stretch
Production and revenue
(existing permits)
Major Projects
20%
20%
Stretch
Stretch
TRCFR 4.07 – consistent with NOPSEMA average of 4.02. Major
work has been undertaken by the Company to enhance HSEC
processes and to prepare and submit regulatory documents to
support being an offshore operator and the increased activity this
has brought.
Production of 1.49 MMboe is at the high end of guidance and
increased gas and oil prices positively impacting revenue.
As at 30 June 2018 the Sole Gas Project was ahead of schedule
and well within budget.
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4. Remuneration Report continued
4.4 FY18 performance and Executive KMP pay outcomes continued
Weighting
Scorecard Result Comment
Key gas strategy milestones
20%
Target
Reserve additions have replaced production. The Company’s clear
South-east Australia strategy has created opportunities such as
the Minerva Gas Plant acquisition and the award of the VIC/P72
exploration permit.
20%
Stretch
Costs are below budget and processes and funding have
improved significantly. External staff survey has been conducted
and concluded high people engagement and enablement.
4.4.3 STIP outcomes continued
Performance measures in
company scorecard
Growth in reserves and resources
Acquisitions and divestments
Cost management
Processes and risk management
People and stakeholder
relationships
4.4.4 LTIP outcomes
The Company’s total shareholder return relative to the peer group against which it is measured is set out below. The graph commences December
2015, the time the first grant of performance rights and share appreciation rights were made under the Company’s Equity Incentive Plan (EIP).
Rights will vest and shares will be issued for the first time under this plan in December 2018. The terms of the EIP are set out in section 4.5.3.
Relative Total Shareholder Return - 15 December 2015 to 30 June 2018
-100%
-50%
0%
50%
100%
150%
200%
250%
300%
350%
Cooper Energy Limited
188%
327%
263%
237%
81%
57%
36%
17%
8%
-45%
-47%
-72%
During the reporting period, shares were issued to Executive KMP on the vesting of performance rights granted in September 2014 under the
2011 Plan. Under that plan, 75% of the performance rights were tested against relative total shareholder return and 25% were tested against
absolute shareholder return after the end of the measurement period.
The results are set out below:
2011 Plan Award
Award 7 (granted September 2014)
Start VWAP
End VWAP
Cooper Energy TSR
TSR Rank
Absolute TSR Achieved
Relative TSR Achieved
0.3938
0.2906
-26.21%
1st against peer group
0.00%
100.00%
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4. Remuneration Report continued
4.5 Nature of Executive KMP remuneration
Executive KMP remuneration during the reporting period consisted of:
• base salary and statutory superannuation;
• short term incentive plan (being performance based cash bonuses);
• other short term benefits such as accommodation, internet allowance and carparking; and
• long term incentive plan (currently comprising the award of performance rights and share appreciation rights under the Company’s Equity
Incentive Plan (EIP)).
It is the Company’s policy that the performance based (or at risk) pay of Executive KMP forms a significant portion of their total remuneration.
In addition, within performance based pay, an appropriate balance is targeted between rewarding operational performance (through the
short term incentive cash bonuses) and rewarding long-term sustainable performance (through the long term incentive plan).
The Company’s remuneration profile for Executive KMP is as follows:
Remuneration
Element
Expressed as percentage of fixed remuneration
at target level performance
Expressed as percentage of fixed remuneration
at maximum (super stretch) level performance
Fixed Remuneration
STIP (at risk)
LTIP1 (at risk)
Total
Managing
Director
100%
50%
100%
250%
Other
Executive
KMP
100%
25%
70%
195%
Managing
Director
100%
100%
100%
300%
Other
Executive
KMP
100%
50%
70%
220%
1. Reflects face value of LTIP at grant date however may not necessarily reflect the amount that will ultimately vest and be exercised.
4.5.1 Fixed Remuneration
Fixed Remuneration includes base salary (paid in cash) and statutory superannuation.
Executives are paid base salaries which are competitive in the markets in which the Company operates and are consistent with the
responsibilities, accountabilities and complexities of the respective roles.
The Company benchmarks Executive KMP base salaries against hydrocarbon industry market surveys which are published annually. Additionally,
the pay levels of Executive 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 base salaries.
4.5.2 Short term incentive plan (STIP) - Overview
The key features of the STIP for the financial year 2018 are set out in the following table:
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.
What is the maximum award opportunity (%
of fixed remuneration)?
Managing Director
Management Team
100%
50%
What is the performance period?
Each year, the Board reviews and approves the performance criteria for the year ahead by
approving a Company scorecard. The Company’s STIP operates over a 12 month performance
period from 1 July to 30 June.
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4.5 Nature of Executive KMP remuneration continued
4.5.2 Short term incentive plan (STIP) - Overview continued
How are the performance measures
determined and what are their
relative weightings?
The measurement of Company performance is based on the achievement of key performance
indicators (KPIs) set out in a Company scorecard. 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 (ie maximum).
Personal performance measures are agreed between each Executive KMP and Cooper Energy
each year. The relative weighting of Company and individual performance varies dependant on
the seniority of the Executive KMP and is as follows:
• Managing Director: 75% Company: 25% individual
• Executives 70% Company; 30% individual
All performance measures are relevant to the Company’s strategic objectives and designed to
motivate Executive KMP to meet goals which enhance shareholder value.
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 expected level of performance (base)). 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.
When are STIP payments made?
STIP payments, are generally made in October each year.
Irrespective of the scorecard outcome, payment of any STIP is entirely at the discretion of
the Board.
4.5.3 Long term incentive plan (LTIP) - Overview
In the reporting period, the LTIP involved grants of performance rights and share appreciation rights under the Equity Incentive Plan approved by
shareholders at the 2015 AGM (EIP). A “refresh” of this approval will be sought at the 2018 AGM. It is proposed that future grants will be made
under the EIP. The key features of the grants made in the 2018 financial year (granted December 2017) are set out in the following table:
Plan Feature
Details
What is the purpose of the LTIP?
How is the LTIP aligned to
shareholder interests?
What is the vehicle 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 3 years before securities under the plan are available to employees).
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.
During the reporting period, the LTIP involved grants of 50% Performance Rights and 50% Share
Appreciation Rights (SARs).
A performance right is a right to acquire one fully paid share in the Company provided a specified
hurdle is met.
Share Appreciation Rights (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 award opportunity (%
of fixed remuneration)?
Managing Director
Executive KMP
Senior staff
120%
70%
50%
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4. Remuneration Report continued
4.5 Nature of Executive KMP remuneration continued
4.5.3 Long term incentive plan (LTIP) - Overview continued
Plan Feature
Details
What is the performance period?
The performance period is 3 years. Additionally, the LTIP allows for re-testing 12 months following
the end of the performance period.
What are the performance measures?
A re-test was considered appropriate because the Company’s growth is dependent on
development of projects that will likely take greater than 3 years from conception to start-
up. Given the growth of the Company, including growth in its development activities and no
longer being reliant on single projects, the Board has considered the re-test provision and has
determined that it will not form part of the grant of Incentives for the 2019 financial year.
100% of the grant (both performance rights and SARs) is subject to a relative total shareholder
return performance (RTSR) measure. RTSR is a common LTI measure across ASX-listed
companies and is aligned with shareholder returns. Relative measures ensure that maximum
incentives are only achieved if Cooper Energy’s performance exceeds that of its peers and
therefore supports competitive returns against other comparable organisations.
In addition to the RTSR performance measure set by the Board, SARs by their nature also have a
natural absolute total shareholder return measure. No SARs will be exercisable unless the share
price appreciates over the measurement period.
What is the vesting schedule?
The level of vesting will be determined based on the ranking against the comparator Group of
companies in accordance with the following schedule:
Which companies make up the Relative TSR
peer group?
• 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
• 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.
The RTSR 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 Limited; AWE Limited; Blue
Energy 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
Australian operations and a range of market capitalisation.
What happens on cessation of employment? Generally, if an employee ceases employment prior to the vesting date, they will forfeit all awards.
Exceptional circumstances may be approved by the Board in the event of redundancy, retirement
or incapacity, and may result in a prorate number of awards being retained.
What happens if there is a change of control? In the event of a change of control, the Board has the discretion to approve pro-rata vesting based
on service and performance.
Who can participate in the LTIP?
Eligibility is generally restricted to Executive KMP and senior staff who are in a position to
influence shareholder value the most.
Staff not offered the opportunity to participate in the LTIP are given the opportunity to become
shareholders by receiving a deferred component of a STIP which will be paid in equity.
Is there a cap on dilution?
5% total on issue (excluding KMP).
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4. Remuneration Report continued
4.5 Nature of Executive KMP remuneration continued
4.5.3 Long term incentive plan (LTIP) - Overview continued
Plan Feature
Details
What is the 2011 Plan referred to in
this Report?
The 2011 plan refers to the Cooper Energy Employee Incentive Plan which was approved by
shareholders at the 2011 annual general meeting. The 2011 Plan has now been superseded by
the Equity Incentive Plan (EIP)approved by shareholders at the 2015 annual general meeting
(such approval to be “refreshed” at the 2018 annual general meeting) and grants are now made
under the EIP. The 2011 Plan is referred to in this Report because some Executive KMP were
granted shares on the vesting of performance rights granted in September 2014 under the 2011
Plan. The last of the performance rights granted under the 2011 Plan have now vested or have
been cancelled.
Will the Company make any changes to the
LTIP for the grant to be made in the 2019
financial year?
The general structure of the LTIP will not change for grants made in the 2019 financial year
however, the Board has determined to make some changes to certain aspects of the LTIP. The
changes are:
• The maximum award opportunity for the Managing Director will be reduced from a grant to the
value of 120% of his fixed annual remuneration to 100%.
• The performance period will remain for 3 years however there will no longer be any re-test at the
end of that period.
4.5.4 Executive KMP employment contracts
Mr David Maxwell – Managing Director
Mr Maxwell commenced as Managing Director on 12 October 2011 under a contract of employment. The initial term of the Managing Director’s
contract expired on 10 October 2014 and was renewed to end on 31 July 2019. On 1 August 2018 Mr Maxwell’s contract of employment was
amended to remove the fixed term and therefore the contract must be terminated in accordance with the notice provisions in the contract of
employment.
The Company may terminate the contract by providing twelve months written notice or payment in lieu of notice. The Company may also
terminate the contract immediately for cause. Mr Maxwell may terminate the contract by providing 6 months’ written notice.
Deed of indemnity
The Company also entered into a deed of indemnity, insurance and access with the Managing Director under which the Company will, on the
terms set out in the deed, provide an indemnity, maintain an appropriate level of Directors’ and Officers’ indemnity insurance and provide access
to Company records.
Other Executive KMP
The Company has entered into a contract of employment with each Executive KMP. The term of each contract continues until termination.
The Company may terminate the contract by providing six months’ notice or payment in lieu of notice. The Company may also terminate the
contract immediately for cause. The Executive may terminate the contract by providing 3 months’ written notice.
4.6 Nature of Non-executive Director remuneration
Non-executive Directors are remunerated solely by way of fees and statutory superannuation and their remuneration is reviewed annually to
ensure that the fees reflect the demands on, and responsibilities of such Directors. Non-executive Directors do not receive any performance
related remuneration.
The maximum aggregate remuneration pool for Non-executive Directors, as approved by shareholders at the Company’s 2014 Annual General
Meeting, is $750,000 per annum. This pool is nearly fully utilised.
Since the 2014 Annual General Meeting, Mr Gordon has changed roles from an Executive Director to a Non-executive Director and Ms Donaghey
joined the Board as a Non-executive Director. The Board has therefore determined to ask shareholders to approve an increase of the aggregate
remuneration pool to $1.25 million at the 2018 Annual General Meeting. This would accommodate the appointment of a new Director if
determined appropriate by the Board and increases to the Directors’ fees in the medium term.
Remuneration paid to the Non-executive Directors for the reporting period and for the previous reporting period is shown in the table in
Section 4.7.3
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.
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4. Remuneration Report continued
4.6 Nature of Non-executive Director remuneration continued
The Company has entered into deeds of indemnity, insurance and access with each of the Non-executive Directors under which the Company
will, on the terms set out in the deed, provide an indemnity, maintain an appropriate level of Directors’ and Officers’ indemnity insurance and
provide access to Company records.
4.7 Statutory remuneration disclosures
4.7.1 Accounting for performance rights
The value of the performance rights issued under the 2011 Plan and EIP is recognised as Share Based Payments in the Company’s statement
of comprehensive income and amortised over the vesting period. Performance rights and share appreciation rights were granted under the
EIP on 8 December 2017. The performance rights and share appreciation rights 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.
Performance rights and share appreciation rights granted under the EIP were valued by an independent consultant who applied the Monte Carlo
simulation model to determine the probability of achievement of the absolute shareholder total return (ASTR), and relative shareholder total
return (RSTR), performance conditions (as described in Section 4.5 above).
The value of performance rights and share appreciation rights shown in the tables below are the accounting fair values for grants in the
reporting period:
Performance Rights (2011 Plan)
Performance Rights (EIP)
Share Appreciation Rights (EIP)
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
2018
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
2018
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
2018
Executive Directors
Mr D. Maxwell
nil
- 1,086,553
100% 1,629,327 $364,969
Executives
Mr A. Thomas
Ms V. Suttell
Ms A. Evans
Mr I. MacDougall
Mr E. Glavas
Mr D. Clegg
Mr M. Jacobsen
nil
nil
nil
nil
nil
nil
nil
- 388,446
100% 498,981
$111,722
-
-
-
487,101
$109,111
- 179,727
100% 400,967
$89,817
- 372,516
100% 498,981
$111,772
- 253,529
100% 445,519
$99,796
-
-
-
-
-
-
594,025 $133,062
498,981
$111,722
-
-
-
-
-
-
-
-
- 4,092,071
$507,417
- 1,253,196
$155,396
- 1,223,358
$151,696
- 1,007,033
$124,872
- 1,253,196
$155,396
- 1,118,925
$138,747
- 1,491,901
$184,996
- 1,253,196
$155,396
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
The vesting date of the performance rights granted on 8 December 2017 is 8 December 2020. The fair value of these rights is $0.224 per right.
These performance rights have a commencement date of 8 December 2017.
The vesting date of the share appreciation rights granted on 8 December 2017 is 8 December 2020. The fair value of these rights is $0.124
per right. These share appreciation rights have a commencement date of 8 December 2017.
66
Director’s Statutory Report
For the year ended 30 June 2018
4. Remuneration Report continued
4.7 Statutory remuneration disclosures continued
4.7.2 Additional remuneration disclosures
Movement in performance rights
The movement during the reporting period in the number of performance rights 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
(2011 Plan)
Held at
1 July 2017
Granted
Lapsed
Vested &
Exercised
Held at
30 June 2018
Directors
Mr D. Maxwell
Mr H. Gordon1
Executives
Mr A. Thomas
Ms V. Suttell
Ms A. Evans
Mr I. MacDougall
Mr E. Glavas
Mr D. Clegg
Mr M. Jacobsen
1,448,737
419,825
517,929
-
239,634
496,689
338,039
-
-
-
-
-
-
-
-
-
-
-
362,184
104,955
1,086,553
314,870
129,483
388,446
-
59,907
124,173
84,510
-
-
-
179,727
372,516
253,529
-
-
-
-
-
-
-
-
-
-
-
1. Performance Rights were granted to Mr Gordon when he was an Executive Director.
The performance rights lapsed during the period noted in the table above were granted in December 2014.
Performance Rights
(EIP)
Held at
1 July 2017
Granted
Lapsed
Vested &
Exercised
Held at
30 June 2018
Directors
Mr D. Maxwell
Mr H. Gordon1
Executives
Mr A. Thomas
Ms V. Suttell
Ms A. Evans
Mr I. MacDougall
Mr E. Glavas
Mr D. Clegg
Mr M. Jacobsen
3,407,214
987,364
1,218,091
-
597,278
1,168,139
868,158
-
-
1,629,327
-
498,981
487,101
400,967
498,981
445,519
594,025
498,981
1. Performance Rights were granted to Mr Gordon when he was an Executive Director.
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
5,036,541
987,364
1,717,072
487,101
998,245
1,667,120
1,313,677
594,025
498,981
67
Director’s Statutory Report
For the year ended 30 June 2018
4. Remuneration Report continued
4.7 Statutory remuneration disclosures continued
4.7.2 Additional remuneration disclosures continued
Share Appreciation
Rights (EIP)
Held at
1 July 2017
Granted
Lapsed
Vested &
Exercised
Held at
30 June 2018
Directors
Mr D. Maxwell
Mr H. Gordon1
Executives
Mr A. Thomas
Ms V. Suttell
Ms A. Evans
Mr I. MacDougall
Mr E. Glavas
Mr D. Clegg
Mr M. Jacobsen
9,334,554
2,705,027
3,337,135
-
1,634,581
3,200,285
2,378,444
-
-
4,092,071
-
1,253,196
1,223,358
1,007,033
1,253,196
1,118,925
1,491,901
1,253,196
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
13,426,625
2,705,027
4,590,331
1,223,358
2,641,614
4,453,481
3,497,369
1,491,901
1,253,196
1. Share Appreciation Rights were granted to Mr Gordon when he was an Executive Director.
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 2017
Purchases
Received on
vesting of performance
rights
Sales
Held at
30 June 2018
Directors
Mr J. Conde AO
Mr D. Maxwell
Ms E. Donaghey
Mr H. Gordon
Mr J. Schneider
Ms A. Williams
Executives
Mr A. Thomas
Ms V. Suttell
Ms A. Evans
Mr I. MacDougall
Mr E. Glavas
Mr D. Clegg
Mr M. Jacobsen
Options
613,638
8,178,656
-
1,360,731
726,138
118,638
245,455
2,112,123
-
-
290,456
47,456
-
1,086,553
-
-
-
-
314,870
632,000
-
-
1,781,364
-
388,446
29,000
430,500
527,592
-
125,000
-
11,600
172,200
162,038
33,060
10,000
-
-
179,727
372,516
253,529
-
-
859,093
11,377,332
-
1,043,601
1,016,594
166,094
2,169,810
40,600
782,427
1,062,146
286,589
135,000
-
-
-
-
-
-
-
-
-
-
No options were issued (or forfeited) during the year.
68
Director’s Statutory Report
For the year ended 30 June 2018
4. Remuneration Report continued
4.7 Statutory remuneration disclosures continued
4.7.3 Table of Directors’ remuneration for 2017 and 2018 financial years
Benefits
Short-term
Base Salary &
Fees
STIP
Other
Short-term
Benefits(a)
Directors
Mr J. Conde AO
$
2018
191,781
2017
161,644
Mr J. Schneider
2018
118,722
2017
103,402
$
-
-
-
-
$
-
-
-
-
Long
Term
Long
Service
Leave
$
-
-
-
-
Mr D. Maxwell
2018
767,451
667,186
78,012
29,253
2017
647,884
498,421
88,691
38,938
Post
Employment
Share Based
Remuneration(c)
Superannuation(b)
LTIP
Total
$
18,219
15,356
11,279
9,823
20,049
19,616
$
-
-
-
-
$
210,000
177,000
130,001
113,225
684,776
2,246,727
554,317
1,847,867
Mr H. Gordon(d)
2018
118,722
23,861
-
2017
212,241
113,472
6,466
Ms A. Williams
2018
118,722
Ms E. Donaghey(e)
2017
103,402
2018
2017
2,101
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
18,689
149,283
310,555
19,476
179,088
530,743
11,279
9,823
200
-
-
-
-
-
130,001
113,225
2,301
-
a) Other short term benefits include fringe benefits on accommodation, car parking and other benefits.
b) Superannuation includes the amounts required to be contributed by the Company and does not include amounts salary sacrificed.
c) 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 performance rights 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 performance rights 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 25 of the Notes to the Financial Statements. None of the performance rights issued vested and
no payments were made for performance rights during the current financial year.
d) Performance rights and share appreciation rights were granted to Mr Gordon when he was an Executive Director.
e) Ms Donaghey was appointed a Non-executive Director of the Company effective from 25 June 2018.
69
Director’s Statutory Report
For the year ended 30 June 2018
4. Remuneration Report continued
4.7 Statutory remuneration disclosures continued
4.7.4 Table of Executives’ remuneration for 2017 and 2018 financial years
Short-term
Base Salary
STIP
Benefits
Other
Short-term
Benefits(a)
Long
Term
Long
Service
Leave
Post
Employment
Share Based
Remuneration(c)
Superannuation(b)
LTIP Termination
Payments
Total
Executives
Mr A. Thomas
$
$
$
$
2018
396,201
161,569
6,382
12,825
2017
362,147
128,902
6,192
14,494
Ms V. Suttell (d)
2018
373,701
175,493
6,382
2017
98,673
26,330
2,453
-
-
Ms A. Evans(e)
2018
297,076
133,698
6,382
20,916
2017
203,658
82,521
6,603
9,134
Mr I. MacDougall
2018
396,201
161,569
6,382
11,780
2017
354,796
127,084
6,649
32,245
Mr E. Glavas
2018
346,201
145,673
6,382
34,033
2017
278,148
113,328
6,466
Mr D. Clegg(f)
2018
435,368
249,958
2017
383,534
21,201
Mr M. Jacobsen(g)
2018
363,634
149,869
Mr J. de Ross(h)
2017
2018
2017
-
-
-
-
158,367
49,031
3,240
536
92
536
-
-
-
-
-
-
-
-
-
$
20,049
19,616
20,049
8,947
20,049
19,616
20,049
19,616
20,049
19,616
20,049
3,269
20,049
-
-
$
$
$
236,115
198,431
50,713
-
132,709
95,395
281,444
146,609
177,141
122,724
61,844
31,500
51,949
-
-
- 833,141
- 729,782
- 626,338
- 136,403
- 610,830
- 416,927
- 877,425
- 686,999
- 729,479
- 540,282
- 767,755
- 439,596
- 586,037
-
-
-
-
18,501
67,696
283,371 580,206
a) Other short term benefits include fringe benefits on accommodation, car parking and other benefits.
b) Superannuation includes the amounts required to be contributed by the Company and does not include amounts salary sacrificed.
c)
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 performance rights 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 performance rights was determined in accordance with AASB 2 Share-based Payments and is discussed in
Section 4.11 above and in more detail in Note 25 of the Notes to the Financial Statements. None of the performance rights issued vested and
no payments were made for performance rights during the current financial year.
d) Ms Suttell commenced employment with the Company in an acting capacity part time (0.8 full time equivalent) on 18 January 2017. She
modified her hours to full time from 1 June 2017.
e) Ms Evans worked part time (0.8 full time equivalent for the period 1 February 2017 to 31 January 2018; and 0.9 full time equivalent for the
period 1 February 2018 to 30 June 2018) and accordingly her entitlements are prorated.
f) Mr Clegg commenced employment with the Company as General Manager Development on 1 May 2017. Prior to that time, he was engaged
by the Company as a contractor on a part time basis and was not considered KMP during this period. The amounts shown in the table above
include the total remuneration paid during the reporting period, including as a contractor.
g) Mr Jacobsen commenced employment with the Company and General Manager Projects on 1 July 2017.
h) Mr de Ross left employment on 9 December 2016. His termination payment included the payout of unused annual leave entitlements.
End of remuneration report.
70
Director’s Statutory Report
For the year ended 30 June 2018
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 Group 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:
Mr J. Conde AO
Mr D. Maxwell
Mr H. Gordon
Mr J. Schneider
Ms A. Williams
Ms E. Donaghey
Cooper Energy Limited
Ordinary Shares
Performance Rights
Share Appreciation Rights
859,093
11,377,332
1,043,601
1,016,594
166,094
-
-
5,036,541
987,364
-
-
-
-
13,426,625
2,705,027
-
-
-
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 17,846,179 outstanding performance rights and 46,017,694 share appreciation rights under the Equity
Incentive Plan approved by shareholders at the 2015 AGM.
During the financial year 4,305,751 shares were issued as a result of performance rights exercised. At the date of this report, no performance
rights have vested and been exercised subsequent to 30 June 2018.
12. Events after financial reporting date
Refer to Note 28 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 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.
No proceedings have been brought or intervened in on behalf of Cooper Energy Limited with leave of the Court under section 237 of the
Corporations Act.
71
Director’s Statutory Report
For the year ended 30 June 2018
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 2018.
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 $172,187 (2017: $65,000). 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 13 August 2018
72
Cooper Energy Limited and its controlled entities
Financial Statements
For the year ended 30 June 2018
73
Consolidated Statement of Comprehensive Income
For the year ended 30 June 2018
Continuing Operations
Revenue from sales
Cost of sales
Gross profit
Other revenue
Gain on sale of subsidiary
Exploration and evaluation expenditure written off
Finance costs
Impairment
Other expenses
Profit/(Loss) before tax
Income tax benefit
Petroleum Resource Rent Tax expense
Total tax expense
Consolidated
2018
$’000
67,452
(38,464)
28,988
4,933
21,934
(850)
(2,779)
(696)
2017
$’000
34,648
(20,058)
14,590
1,614
-
(1,577)
(2,555)
-
(20,511)
(19,107)
31,019
4,781
(8,789)
(4,008)
(7,035)
4,786
(7,598)
(2,812)
Notes
4
4
4
6
4
13
4
5
Net profit/(loss) after tax from continuing operations
27,011
(9,847)
Discontinued operations
Loss for the year from discontinued operations
Total profit/(loss) for the period attributable to shareholders
Other comprehensive income/(expenditure)
Items that will be reclassified subsequently to profit or loss
Foreign currency translation reserve
Reclassification of foreign currency translation reserve on disposal of subsidiary
Fair value movements on oil price options accounted for in a hedge relationship
Fair value movements on interest rate swaps accounted for in a hedge relationship
Reclassification during the period to profit or loss of realised hedge settlements
21
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
11
Other comprehensive income/(expenditure) for the period net of tax
-
27,011
(2,465)
(12,312)
-
-
258
(481)
280
92
1,230
1,379
(297)
(835)
736
-
494
(369)
(132)
(403)
Total comprehensive gain/(loss) for the period attributable to shareholders
28,390
(12,715)
Basic earnings per share from continuing operations
Diluted earnings per share from continuing operations
Basic earnings per share
Diluted earnings per share
7
7
7
7
cents
1.8
1.8
1.8
1.8
cents
(1.4)
(1.4)
(1.8)
(1.8)
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 2018
Consolidated
2018
$’000
2017
$’000
Notes
Assets
Current Assets
Cash and cash equivalents
Other financial assets
Trade and other receivables
Inventory
Prepayments
Assets classified as held for sale
Total Current Assets
Non-Current Assets
Equity instruments
Trade and other receivables
Prepayments
Term deposits at banks
Other financial assets
Deferred tax assets
Oil and gas assets
Property, plant and equipment
Exploration and evaluation
Total Non-Current Assets
Total Assets
Liabilities
Current Liabilities
Trade and other payables
Provisions
Other financial liabilities
Liabilities and provisions classified as held for sale
Total Current Liabilities
Non-Current Liabilities
Deferred Petroleum Resource Rent Tax liability
Provisions
Government grants
Interest bearing loans and borrowings
Other financial liabilities
Total Non-Current Liabilities
Total Liabilities
Net Assets
Equity
Contributed equity
Reserves
Accumulated losses
Total Equity
8
20
9
10
11
9
10
8
20
5
12
14
15
16
17
20
5
17
18
20
19
19
19
The above Consolidated Statement of Financial Position should be read in conjunction with the accompanying notes.
236,907
147,425
20,171
27,330
467
2,761
287,636
-
287,636
2,241
156
-
16
20,146
10,334
394,632
2,864
98,732
529,121
816,757
59,215
73,812
591
133,618
-
-
10,878
2,000
1,902
162,205
25,090
187,295
658
2,997
911
41
-
4,315
69,402
3,694
223,331
305,349
492,644
58,520
19,188
114
77,822
25,448
133,618
103,270
10,356
106,680
2,067
116,923
3,231
239,257
1,481
99,802
-
-
3,044
104,327
372,875
207,597
443,882
285,047
471,837
9,925
(37,880)
443,882
343,161
6,777
(64,891)
285,047
75
Consolidated Statement of Changes in Equity
For the year ended 30 June 2018
Balance at 1 July 2017
Profit for the period
Other comprehensive income
Total comprehensive income for the period
Transactions with owners in their capacity as owners:
Share based payments
Transferred to issued capital
Share issued
Balance at 30 June 2018
Balance at 1 July 2016
Loss for the period
Other comprehensive expenditure
Total comprehensive expenditure for the period
Transactions with owners in their capacity as owners:
Share based payments
Transferred to issued capital
Shares issued
Balance at 30 June 2017
Issued Capital
Reserves
Accumulated
Losses
$’000
$’000
$’000
343,161
-
-
-
-
873
127,803
471,837
137,558
-
-
-
223
1,440
203,940
343,161
6,777
-
1,379
1,379
2,642
(873)
-
9,925
6,571
-
(403)
(403)
2,049
(1,440)
-
6,777
(64,891)
27,011
-
27,011
-
-
-
(37,880)
(52,579)
(12,312)
-
(12,312)
-
-
-
(64,891)
Total
Equity
$’000
285,047
27,011
1,379
28,390
2,642
-
127,803
443,882
91,550
(12,312)
(403)
(12,715)
2,272
-
203,940
285,047
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 2018
Consolidated
2018
$’000
2017
$’000
Notes
Cash Flows from Operating Activities
Receipts from customers
Payments to suppliers and employees
Exit penalties
Payments for restoration
Petroleum Resource Rent Tax paid
Interest received
Net cash from operating activities
Cash Flows from Investing Activities
Transfers of term deposits
Transfers to escrow proceeds receivable
Receipts from disposal of property, plant and equipment
Payments of contingent consideration
Payments of consideration
Receipts for assumption of rehabilitation provisions
Receipts from sale of subsidiary
Payments for exploration and evaluation
Net cash transfer on disposal of subsidiary
Acquisition of exploration and evaluation and gas assets
Interest paid
Payments for oil and gas assets
Net cash flows used in investing activities
Cash Flows from Financing Activities
Proceeds from equity issue
Proceeds from borrowings
Transaction costs associated with borrowings
Net cash flow from financing activities
Net increase/(decrease) in cash held
Net foreign exchange differences
Cash and Cash Equivalents At 1 July
Cash and Cash Equivalents At 30 June
65,065
(27,521)
-
(12,413)
(6,706)
3,793
22,218
25
(40,171)
41,847
(20,000)
(1,000)
48,082
739
(26,283)
-
-
(4,597)
(172,176)
(173,534)
127,228
125,865
(12,295)
240,798
89,482
-
147,425
236,907
8
8
The above Consolidated Statement of Cash Flows should be read in conjunction with the accompanying notes.
36,917
(27,965)
(3,703)
-
(2,785)
1,614
4,078
50
-
-
-
-
-
500
(32,149)
(1,261)
(65,000)
-
(9,937)
(107,797)
201,934
-
-
201,934
98,215
(507)
49,717
147,425
77
Notes to the Financial Statements
For the year ended 30 June 2018
1. Corporate information
The consolidated financial report of Cooper Energy Limited (the parent entity) for the year ended 30 June 2018 was authorised for issue in
accordance with a resolution of the Directors on 13 August 2018.
Cooper Energy Limited is a 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 section 5 of the Directors’ Statutory Report.
2. Summary of significant accounting policies
a) 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 and Australian Accounting Standards and other authoritative pronouncements of the Australian Accounting Standards Board.
The financial report has also been prepared on a historical cost basis, except for equity instruments measured at fair value through other
comprehensive income and derivative financial instruments measured at fair value. Cooper Energy Limited is a for profit Company.
The financial report is presented in Australian dollars and all values are rounded to the nearest thousand dollars ($’000) unless otherwise stated
under the option available to the Group under ASIC Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191. The Group
is an entity to which the legislative instrument applies.
Significant event and transaction
Final Investment Decision for the Sole Gas Project
Final Investment Decision (“FID”) for the Sole Gas Project was announced by the Company on 29 August 2017. This was a result of achieving
full funding of the Sole Gas Project through a fully underwritten accelerated non-renounceable 2 for 5 entitlement offer and with the execution of
a fully underwritten debt finance package. The project involves development of the Sole field to commence supply of gas to south-east Australia
in 2019. Declaration of Sole FID fulfilled one of the key conditions for the completion of the agreement with APA Group (discussed below). The
achievement of FID also triggered a $20.0 million payment of contingent consideration to Santos Limited.
Upon reaching FID, the Sole exploration and evaluation assets were assessed for impairment and subsequently transferred to development due
to the technical feasibility and commercial viability of gas production becoming evident in accordance with AASB 6.
Completion of the sale of the Orbost Gas Plant
The sale of the Orbost Gas Plant to APA Group, originally announced on 27 February 2017, completed on 31 October 2017. As part of the
transaction, the Company received $20.0 million which is held in escrow and will be released to the Company upon satisfaction of certain
conditions; these funds are shown on the balance sheet as a financial asset. Additionally, on completion the Company was reimbursed by APA
Group for certain development costs incurred in respect of the Orbost Gas Plant to the value of $24.4 million. A gain on sale of $21.9 million
(net of transaction costs) is recognised in the Consolidated Statement of Comprehensive Income. Refer to Note 6 for further information.
Syndicated Facility Agreement and draw down
On 29 August 2017 the Company executed a fully underwritten finance package including a senior secured $250.0 million syndicated bank
debt facility underwritten by ANZ and Natixis and a senior secured $15.0 million working capital facility provided by ANZ. Additional lender
support was provided during the 2018 financial year with ABN AMRO, ING and NAB substituting into the syndicated bank debt facility with ANZ
and Natixis.
As at 30 June 2018 the Company had drawn $125.9 million of the syndicated bank debt facility. Net of costs of $8.9 million non-current
borrowings are $116.9 million on the balance sheet. Refer to note 18 for further information.
Assumption of BMG rehabilitation provision
During the period, the Company assumed an additional 51% of the rehabilitation provision associated with the legacy oil infrastructure at BMG as
a result of entering into deeds of release with three exited parties. As settlement of their liabilities, Cooper Energy received $48.1 million from the
exited parties.
b) Statement of compliance
The financial report complies with Australian Accounting Standards and International Financial Reporting Standards (“IFRS”) as issued by the
International Accounting Standards Board.
(i) Changes in accounting policy and disclosures
As at 1 July 2015, Cooper Energy early adopted AASB 9 Financial Instruments (2014). AASB 9 (December 2014) is a new standard which replaces
AASB 139 (as amended). This new version supersedes AASB 9 issued in December 2009 (as amended) and AASB 9 (issued in December
2010) and includes a model for classification and measurement, a single, forward-looking ‘expected loss’ impairment model and a substantially-
reformed approach to hedge accounting, The impact for Cooper Energy has been outlined in Note 23 of the 2016 Financial Statements.
78
Notes to the Financial Statements
For the year ended 30 June 2018
2. Summary of significant accounting policies continued
b) Statement of compliance continued
The Group’s accounting policies are consistent with those of the previous financial year except for new policies adopted from 1 July 2017
as follows:
AASB 2016-1
Summary
Amendments to Australian Accounting Standards – Recognition of Deferred Tax Assets for
Unrealised Losses [AASB 112]
This Standard amends AASB 112 Income Taxes (July 2004) and AASB 112 Income Taxes (August
2015) to clarify the requirements on recognition of deferred tax assets for unrealised losses on debt
instruments measured at fair value.
Application Date of the Standard
1 January 2017
Application Date for Group
1 July 2017
Impact on Group Financial report
The adoption of this standard did not have a material impact on the Group.
AASB 2016-2
Summary
Amendments to Australian Accounting Standards – Disclosure Initiative: Amendments to
AASB 107
The amendments to AASB 107 Statement of Cash Flows are part of the IASB’s Disclosure Initiative
and help users of financial statements better understand changes in an entity’s debt. The
amendments require entities to provide disclosures about changes in their liabilities arising from
financing activities, including both changes arising from cash flows and non-cash changes (such as
foreign exchange gains or losses).
Application Date of the Standard
1 January 2017
Application Date for Group
1 July 2017
Impact on Group Financial report
Additional disclosures have been included in note 8.
AASB 2017-2
Summary
Amendments to Australian Accounting Standards – Further Annual Improvements 2014-2016 Cycle
This Standard clarifies the scope of AASB 12 Disclosure of Interests in Other Entities by specifying
that the disclosure requirements apply to an entity’s interests in other entities that are classified as
held for sale or discontinued operations in accordance with AASB 5 Non-current Assets Held for Sale
and Discontinued Operations.
Application Date of the Standard
1 January 2017
Application Date for Group
1 July 2017
Impact on Group Financial report
The adoption of this standard did not have a material impact on the Group.
79
2. Summary of significant accounting policies continued
b) Statement of compliance continued
(ii) Accounting standards and interpretations issued but not yet effective
The accounting standards and interpretations that have recently been issued or amended but are not yet effective and have not been adopted by
the Group for the annual reporting period ending 30 June 2018, are outlined below:
AASB 15
Summary
Revenue from Contracts with Customers
In October 2015, the AASB issued AASB 15 Revenue from Contracts with Customers, which replaces
AASB 111 Construction Contracts, AASB 118 Revenue and related Interpretations (AASB Interpretation 13
Customer Loyalty Programmes, AASB 15 Agreements for the Construction of Real Estate, IFRIC 18
Transfers of Assets from Customers and AASB Interpretation 131 Revenue—Barter Transactions Involving
Advertising Services).
The core principle of AASB 15 is that an entity recognises revenue to depict the transfer of promised goods
or services to customers in an amount that reflects the consideration to which the entity expects to be
entitled in exchange for those goods or services. An entity recognises revenue in accordance with that core
principle by applying the following steps:
(a) Step 1: Identify the contract(s) with a customer
(b) Step 2: Identify the performance obligations in the contract
(c) Step 3: Determine the transaction price
(d) Step 4: Allocate the transaction price to the performance obligations in the contract
(e) Step 5: Recognise revenue when (or as) the entity satisfies a performance obligation
Early application of this standard is permitted.
AASB 2014-5 incorporates the consequential amendments to a number Australian Accounting Standards
(including Interpretations) arising from the issuance of AASB 15.
Application Date of the Standard
1 January 2018
Application Date for Group
1 July 2018
Impact on Group Financial report
At this point the Company has assessed individual contracts, which has indicated the adoption of the
standard is not expected to have a material impact. The Company will apply the full retrospective
approach on transition and there will be no adjustment to profit and loss. Additional disclosures on
contract details and performance obligations will be required and minor presentation changes of
amounts in the Statement of Comprehensive Income will arise.
AASB 2014-10
Summary
Amendments to Australian Accounting Standards – Sale or Contribution of Assets between an
Investor and its Associate or Joint Venture
AASB 2014-10 amends AASB 10 Consolidated Financial Statements and AASB 128 to address an
inconsistency between the requirements in AASB 10 and those in AASB 128 (August 2011), in dealing
with the sale or contribution of assets between an investor and its associate or joint venture. The
amendments require:
(a) a full gain or loss to be recognised when a transaction involves a business (whether it is housed in a
subsidiary or not); and
(b) a partial gain or loss to be recognised when a transaction involves assets that do not constitute a
business, even if these assets are housed in a subsidiary.
AASB 2014-10 also makes an editorial correction to AASB 10. AASB 2017-5 further defers the effective
date of the amendments made in AASB 2014-10 to periods beginning on or after 1 January 2022.
Application Date of the Standard
1 January 2022
Application Date for Group
1 July 2022
Impact on Group Financial report
The adoption of this standard in the current format is not expected to have a material impact on
the Group.
80
Notes to the Financial StatementsFor the year ended 30 June 2018 2. Summary of significant accounting policies continued
b) Statement of compliance continued
AASB 2016-5
Summary
Classification and Measurement of Share-based Payment Transactions
This standard amends to AASB 2 Share-based Payment, clarifying how to account for certain types of
share-based payment transactions. The amendments provide requirements on the accounting for:
• The effects of vesting and non-vesting conditions on the measurement of cash-settled share-based
payments
• Share-based payment transactions with a net settlement feature for withholding tax obligations
• A modification to the terms and conditions of a share-based payment that changes the classification
of the transaction from cash-settled to equity-settled
Application Date of the Standard
1 January 2018
Application Date for Group
1 July 2018
Impact on Group Financial report
The adoption of this standard is not expected to have a material impact on the Group.
AASB 2017-1
Amendments to Australian Accounting Standards – Transfers of Investments Property, Annual
Improvements 2014-2016 Cycle and Other Amendments
Summary
The amendments clarify certain requirements in:
• AASB 1 First-time Adoption of Australian Accounting Standards –deletion of exemptions for first-
time adopters and addition of an exemption arising from AASB Interpretation 22 Foreign Currency
Transactions and Advance Consideration
• AASB 12 Disclosure of Interests in Other Entities – clarification of scope
• AASB 128 Investments in Associates and Joint Ventures – measuring an associate or joint venture at
fair value
• AASB 140 Investment Property – change in use.
Application Date of the Standard
1 January 2018
Application Date for Group
1 July 2018
Impact on Group Financial report
The adoption of this standard is not expected to have a material impact on the Group.
81
Notes to the Financial StatementsFor the year ended 30 June 2018 2. Summary of significant accounting policies continued
b) Statement of compliance continued
AASB 16
Summary
Leases
The key features of AASB 16 are as follows:
Lessee accounting
• Lessees are required to recognise assets and liabilities for all leases with a term of more than 12
months, unless the underlying asset is of low value.
• A lessee measures right-of-use assets similarly to other non-financial assets and lease liabilities
similarly to other financial liabilities.
• Assets and liabilities arising from a lease are initially measured on a present value basis. The
measurement includes non-cancellable lease payments (including inflation-linked payments), and
also includes payments to be made in optional periods if the lessee is reasonably certain to exercise
an option to extend the lease, or not to exercise an option to terminate the lease.
• AASB 16 contains disclosure requirements for lessees.
Lessor accounting
• AASB 16 substantially carries forward the lessor accounting requirements in AASB 117. Accordingly,
a lessor continues to classify its leases as operating leases or finance leases, and to account for those
two types of leases differently.
• AASB 16 also requires enhanced disclosures to be provided by lessors that will improve information
disclosed about a lessor’s risk exposure, particularly to residual value risk.
AASB 16 supersedes:
(a) AASB 117 Leases
(b) Interpretation 4 Determining whether an Arrangement contains a Lease
(c) SIC-15 Operating Leases—Incentives
(d) SIC-27 Evaluating the Substance of Transactions Involving the Legal Form of a lease
The new standard will be effective for annual periods beginning on or after 1 January 2019. Early
application is permitted, provided the new revenue standard, AASB 15 Revenue from Contracts with
Customers, has been applied, or is applied at the same date as AASB 16.
Application Date of the Standard
1 January 2019
Application Date for Group
1 July 2019
Impact on Group Financial report
The Group is still assessing the impact of this standard.
AASB Interpretation 22
Foreign Currency Transactions and Advance Consideration
Summary
The Interpretation clarifies that in determining the spot exchange rate to use on initial recognition of
the related asset, expense or income (or part of it) or on the derecognition of a non-monetary asset or
non-monetary liability relating to advance consideration, the date of the transaction is the date on
which an entity initially recognises the non-monetary asset or non-monetary liability arising from the
advance consideration. If there are multiple payments or receipts in advance, then the entity must
determine a date of the transactions for each payment or receipt of advance consideration.
Application Date of the Standard
1 January 2018
Application Date for Group
1 July 2018
Impact on Group Financial report
The adoption of this standard is not expected to have a material impact on the Group.
82
Notes to the Financial StatementsFor the year ended 30 June 2018 2. Summary of significant accounting policies continued
b) Statement of compliance continued
AASB Interpretation 23
Uncertainty over Income Tax Treatments
Summary
The Interpretation clarifies the application of the recognition and measurement criteria in IAS 12
Income Taxes when there is uncertainty over income tax treatments. The Interpretation specifically
addresses the following:
• Whether an entity considers uncertain tax treatments separately
• The assumptions an entity makes about the examination of tax treatments by taxation authorities
• How an entity determines taxable profit (tax loss), tax bases, unused tax losses, unused tax credits and
tax rates
• How an entity considers changes in facts and circumstances.
Application Date of the Standard
1 January 2019
Application Date for Group
1 July 2019
Impact on Group Financial report
The adoption of this standard is not expected to have a material impact on the Group.
The Group has not early adopted any other standard, interpretation or amendment that has been issued but is not yet effective.
c) Basis of consolidation
The consolidated financial statements are those of the consolidated entity, comprising Cooper Energy Limited (“the parent entity”) and its
subsidiaries (“the Group”).
The financial statements of subsidiaries are prepared for the same reporting period as the parent entity, using consistent accounting policies.
Adjustments are made to bring into line any dissimilar accounting policies that may exist. 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 control is transferred to the Group and cease to be consolidated from the date on which
control is transferred out of the Group.
d) Business combinations and asset acquisitions
Business combinations
Business combinations are accounted for using the acquisition method. The cost of 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 assumed for appropriate classification and designation in
accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation
of embedded derivatives in host contracts by the acquiree.
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 either in profit or
loss or as a change to other comprehensive income. 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.
Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised for non-
controlling interest over the net identifiable assets acquired and liabilities assumed. If this consideration is lower than the fair value of the net
assets of the subsidiary acquired, the difference is recognised in profit or loss.
After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill
acquired in a business combination is, from the acquisition date, allocated to each of the Group’s cash-generating units that are expected to
benefit from the combination, irrespective of how those other assets or liabilities had been allocated by the acquiree.
Where goodwill forms part of the cash generating unit and part of the operation within that unit is disposed of, the goodwill associated with the
operation disposed of is included in the carrying amount of the operation when determining the gain or loss on disposal of the operation.
Goodwill disposed of in this circumstance is measured based on the relative values of the operation disposed of and the portion of the cash-
generating unit retained.
Asset acquisitions
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 acuqisition. Under this method transaction costs are capitalised to the
asset and not expensed.
83
Notes to the Financial StatementsFor the year ended 30 June 2018 2. Summary of significant accounting policies continued
e) Joint arrangements
The Group has interests in arrangements that are controlled jointly. A joint arrangement is either a joint operation or a joint venture. The Group
has a number of 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. Currently the Group does
not have any interests in joint ventures.
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
f) Foreign currency
The functional and presentation currency of the Company is Australian dollars.
Translation of foreign currency transactions
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.
Translation of the financial result of foreign operations
An entity’s functional currency is the currency of the primary economic environment in which the entity, or a significant component of the
entity, operates.
g) Investments
Equity instruments at fair value through other comprehensive income
Investments are classified as equity instruments at fair value through other comprehensive income based on an election made at inception
and are initially recognised at fair value plus any directly attributable transaction costs. The classification depends on the purpose for which the
investments were acquired.
After initial recognition, investments are remeasured to fair value. Changes in the fair value of equity investments are recognised as a separate
component of equity. The equity reserve will never be recycled through profit or loss. Any dividends received are reflected in profit or loss.
For investments that are actively traded in organised financial markets, fair value is determined by reference to stock exchange quoted market bid
prices at the close of business on the Consolidated Statement of Financial Position date. Where investments are not actively traded, fair value is
established by using other market accepted valuation techniques.
Investments in associates
An associate is an entity over which the Group has significant influence. Investments in associates are initially recognised at cost. Any surplus
over the Group’s share in the associates net assets on acquisition is accounted for as goodwill; any deficit is treated as an accounting gain and
recognise immediately in the income statement.
After initial recognition, the Group recognises its share of the associate’s profit or loss.
h) Revenue and cost recognition
Revenue is recognised and measured at fair value of consideration received or receivable to the extent that it is probable that the economic
benefits will flow to the Group and the revenue can be reliably measured. The following specific recognition criteria must also be met before
revenue is recognised:
Revenues and costs from production sharing contracts
Revenue earned and production costs incurred from a production sharing contract are recognised when title to the product passes to the
customer and is based upon the Group’s share of sales and costs relating to oil production that are allocated to the Group under the contract.
Interest revenue
Interest revenue is recognised as interest accrues using the effective interest rate, which 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.
Joint venture fees
Joint venture fees are in respect of the Group’s parent’s ability to recover overhead costs relating to operated activities. Joint venture fees include
overhead recoveries on operated activities, parent Company overheads, operator overhead allowances and other indirect charges. Revenue is
recognised when the Group’s right to receive payment is established or services are rendered.
84
Notes to the Financial StatementsFor the year ended 30 June 2018 2. Summary of significant accounting policies continued
i) Depreciation and amortisation
Oil and gas assets are amortised on the Units of Production basis using the latest approved estimate of Proved and Probable (2P) Reserves.
Amortisation is charged only once production has commenced. No amortisation is charged on areas under development where production has
not commenced.
Depreciation on property plant and equipment is calculated at between 7.5% and 37.5% per annum using the diminishing value method over
their estimated useful lives.
j) Employee benefits
Provision is made for employee benefits accumulated as a result of employees rendering services up to the end of the reporting period. These
benefits included wages and salaries, including non-monetary benefits and annual leave. Liabilities 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 general provisions for long service leave are 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 is set out in the Remuneration Report.
k) Share based payments
The Group provides benefits to employees (including Executive Directors) 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.
85
Notes to the Financial StatementsFor the year ended 30 June 2018 2. Summary of significant accounting policies continued
l) Leases
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.
Finance leases, which transfer to the Group substantially all the risks and benefits incidental to ownership of the leased item, are capitalised at the
inception of the lease at the fair value of the leased asset or, if lower, at the present value of the minimum lease payments. Lease payments are
apportioned between the finance charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance
of the liability. Finance charges are recognised as an expense in profit or loss.
Capitalised lease assets are depreciated over the shorter of the estimated useful life of the asset and the lease term if there is no reasonable
certainty that the Group will obtain ownership by the end of the lease term.
Operating lease payments are recognised as an expense in the Consolidated Statement of Comprehensive Income on a straight-line basis over the
lease term.
m) Income tax
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. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted by the
Consolidated Statement of Financial Position date.
Deferred income tax is provided on all temporary differences at the Consolidated Statement of Financial Position date between the tax bases of
assets and liabilities and their carrying amounts for financial reporting purposes.
Deferred income tax liabilities are recognised for all taxable temporary differences except:
• when the deferred income tax liability arises from the initial recognition of goodwill or of an asset or liability in a transaction that is not a business
combination and that, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; or
• when 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, except:
• when the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a
transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss;
or
• when the deductible temporary difference is associated with investments in subsidiaries, associates or interest in joint ventures, in which case
a deferred tax asset is only recognised to the extent that it is probable that the temporary difference will reverse in the foreseeable future and
taxable profit will be accessible against which the temporary difference can be utilised.
Future taxable profits are estimated by Board approved internal budgets and forecasts.
The carrying amount of deferred income tax assets is reviewed at each Consolidated Statement of Financial Position 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 assessed at each Consolidated Statement of Financial Position 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. Where allowable by initial recognition
exemptions, deferred tax assets and deferred tax liabilities that arise on acquisition are netted off against each other.
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 Consolidated Statement of Financial
Position 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.
n) Other taxes
Goods and Services Taxes (“GST”)
Revenues, expenses and assets are recognised net of the amount of Goods and Services Taxes (“GST”) except:-
• where the GST incurred on a purchase of goods and services is not recoverable from the taxation authority, in which case the GST is recognised
as part of the cost of acquisition of the asset or as part of the expense item as applicable; and
• receivables and payables are stated with the amount of GST included.
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.
86
Notes to the Financial StatementsFor the year ended 30 June 2018 2. Summary of significant accounting policies continued
n) Other taxes continued
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.
Commitments and contingencies are disclosed net of the amount of GST recoverable from, or payable to, the taxation authority.
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.
o) Exploration and evaluation expenditure
Exploration and evaluation expenditure includes costs incurred in the search for hydrocarbon resources and determining its commercial viability
in each identifiable area of interest. Exploration and evaluation expenditure is accounted for in accordance with the successful efforts method and
is capitalised to the extent that:
i. the rights to tenure of the areas of interest are current and the 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, will comprise an individual prospective oil or gas field.
Exploration and evaluation expenditure which does not satisfy these criteria is written off. Specifically, costs carried forward in respect of an area
of interest that is abandoned or costs relating directly to the drilling of an unsuccessful well are written off in the year in which the decision to
abandon is made or the results of drilling are concluded. The success or otherwise of a well is determined by reference to the drilling objectives
for that well. For successful wells, the well costs remain capitalised on the 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. A regular review is undertaken of each
area of interest to determine the appropriateness of continuing to carry forward costs in relation to that area of interest.
Where an ownership interest in an exploration and evaluation asset is exchanged for another, the transaction is recognised by reference to the
carrying value of the original interest. Any cash consideration paid, including transaction costs, is accounted for as an acquisition of exploration
and evaluation assets. Any cash consideration received, net of transaction costs, is treated as a recoupment of costs previously capitalised with
any excess accounted for as a gain on disposal of non-current assets.
Where a discovered oil or gas field enters the development phase the accumulated exploration and evaluation expenditure is transferred to oil and
gas assets.
p) Oil and gas assets
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.
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 during the financial period in which they are incurred.
q) Provision for restoration
The Group records the present value of its share of the estimated cost to restore operating locations. 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 on an annual basis.
When the liability is recorded the carrying amount of the production or exploration asset is increased by the restoration costs and are depreciated
over the producing life of the asset. 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 producing life of the asset. Where it is not
appropriate to recognise an asset, changes will go through profit or loss. Any change in the discount rate is applied prospectively.
These estimated costs, whilst based on anticipated technological and legal requirements, assume no significant changes will occur in relevant
State, Federal and International legislation.
87
Notes to the Financial StatementsFor the year ended 30 June 2018 2. Summary of significant accounting policies continued
r) Property, plant and equipment
Property, plant and equipment are stated at historical cost less accumulated depreciation and any accumulated impairment losses. 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. All other repairs and
maintenance are charged to the Consolidated Statement of Comprehensive Income during the financial period in which they are incurred.
The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at each Consolidated Statement of Financial Position date.
Gains and losses on disposals are determined by comparing proceeds with the carrying amount. These are included in the statement of
comprehensive income.
An item of property, plant and equipment is de-recognised upon disposal or when no further future economic benefits are expected from its use.
Any gains or losses arising on de-recognition of the asset (calculated as the difference between the net disposal proceeds and the net carrying
amount of the asset) is included in the statement of comprehensive income in the period the asset is de-recognised.
s) Impairment of non-current assets
The carrying values of non-current assets, including, property, plant and equipment and oil and gas assets are reviewed for impairment at each
reporting date, with recoverable amount being estimated when events or changes in circumstances indicate that the carrying value may be
impaired. The recoverable amount of non-current assets is the higher of fair value less cost to sell and value in use.
An impairment loss is recognised for the amount by which the asset or cash generating unit’s carrying amount exceeds its recoverable amount.
For the purposes of assessing impairment, assets are grouped at the lowest
levels for which there are separately identifiable cash flows (cash generating units). In assessing value-in-use, 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. Where the recoverable amount is based on the fair value less cost to sell the inputs are consistent with the level 3 fair value hierarchy.
Further details on the significant judgements used in impairment testing of non-current assets are in note 2 bb (ii).
t) Cash and cash equivalents
Cash and short term deposits in the Consolidated Statement of Financial Position comprise cash at bank and short term deposits generally with an
original maturity of three months or less. For the purposes of the Statement of Cash Flows, cash and cash equivalents includes cash on hand and
in banks, and money market investments readily convertible to cash within 90 days from date of investment, net of outstanding bank overdrafts.
Cash held in escrow with associated restrictions whereby the Company cannot use that cash for operational purposes as it deems appropriate is
classified as a financial asset and not as cash and cash equivalents.
u) Trade and other receivables
Trade receivables, which generally have 30 to 90 day terms, are recognised and carried at original invoice amount less an allowance for any
uncollectible amounts.
An allowance for doubtful debts is made in accordance with the expected credit loss method. An allowance for doubtful debts is raised at an
amount equal to the lifetime expected credit losses if the credit risk on the financial instrument has increased significantly since initial recognition.
If the credit risk has not increased significantly since initial recognition, the loss allowance is recognised at an amount equal to the lifetime
expected credit losses. Bad debts are written off when identified.
v) Inventory
Inventories are carried at the lower of their cost or net realisable value. Inventories held by the Group are in respect of stores and spares involved
in drilling operations.
w) Trade and other payables
Trade payables and other payables are carried at amortised costs and represent liabilities for goods and services provided to the Group prior to the
end of the financial year that are unpaid and arise when the Group becomes obliged to make future payments in respect of the purchase of these
goods and services.
x) Provisions
Provisions are recognised when the Group has a legal or constructive obligation to make a future sacrifice of economic benefits to other entities 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.
Provisions are not recognised for future operating losses. Where there are a number of similar obligations, the likelihood that an outflow will be
required in settlement is determined by considering the class of obligations as a whole. A provision is recognised even if the likelihood of an
outflow with respect to any one item included in the same class of obligations may be small.
88
Notes to the Financial StatementsFor the year ended 30 June 2018 2. Summary of significant accounting policies continued
y) Contributed equity
Issued and paid up capital is recognised as the fair value of the consideration received by the Group.
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.
z) Earnings per share
Basic earnings per share are calculated as net profit attributable to members divided by the weighted average number of ordinary shares.
Diluted earnings per share is calculated as net profit attributable to members 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.
aa) Derivative financial instruments
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 other comprehensive income may be designated as hedging instruments in cash flow hedges.
Cash flow hedges
The Group uses oil price options as hedges of its exposure to commodity price risk and 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 if its designation as a hedge is revoked,
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.
bb) Significant accounting judgements, estimates and assumptions
(i) Significant accounting judgements
In the process of applying the Group’s accounting policies, management has made the following judgements, apart from those involving
estimations, which have the most significant effect on the amounts recognised in the financial statements:
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.
Taxation
The Group’s accounting policy for taxation requires management’s judgement 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 (Imposition – General) Act 2011, 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.
89
Notes to the Financial StatementsFor the year ended 30 June 2018 2. Summary of significant accounting policies continued continued
bb) Significant accounting judgements, estimates and assumptions continued
(i) Significant accounting judgements continued
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.
Operating lease commitments
The Group has entered into commercial property leases. The Group has determined that is does not retain any of the significant risks and
rewards of ownership of these properties and has thus classified the leases as operating leases.
(ii) Significant accounting estimates and assumptions
The carrying amounts of certain assets and liabilities are often determined based on estimates and assumptions of future events. The key
estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of certain assets and liabilities
within the next annual reporting period are:
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 Company’s Hydrocarbon Guidelines (www.cooperenergy.com.au/policies). 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.
Impairment of capitalised exploration and evaluation expenditure
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 become 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. 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 testing at 30 June 2018 showed impairment was required to be recognised on the Group’s exploration and evaluation expenditure as
set out in note 13.
Impairment of oil and gas assets and property, plant & equipment
The Group reviews the carrying amount of oil and gas assets and property, plant & equipment at each reporting date starting with analysis of any
indicators of impairment. Where indicators of impairment are present, the Group will test whether the cash generating unit’s recoverable amount
exceeds its carrying amount.
The Group performs a value in use calculation of an asset or cash generating unit using a discounted cash flow model. 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, capital expenditure for any development required to produce 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 oil price assumptions (real) are US$65/bbl for FY19,
US$67/bbl for FY20 and US$68/bbl long term. The Group’s gas price assumptions are based on contracted gas prices for contracted gas
volumes, and the Group’s view of future uncontracted gas price assumptions based on market data available, and assessments of the South-east
Australia gas market supply and demand.
90
Notes to the Financial StatementsFor the year ended 30 June 2018 2. Summary of significant accounting policies continued continued
bb) Significant accounting judgements, estimates and assumptions continued
(ii) Significant accounting estimates and assumptions continued
Discount rates applied in the net present value calculation of the value in use are derived from the weighted average cost of capital. The Group
applied a pre-tax real discount rate of 11.7%.
The sensitivity of the impairment models to these assumptions is tested as part of this process and shows that the models are most sensitive to
management’s assumptions relating to production, commodity prices and discount rates. In the event that future circumstances vary from the
assumptions used in the impairment assessment, the recoverable amount of the Groups assets or cash generating units could change materially
and result in an impairment loss.
Impairment testing at 30 June 2018 showed no impairment was required to be recognised with respect to the Group’s oil and gas assets and
property, plant and equipment.
Provisions for decommissioning and 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 well’s life. In determining an appropriate level of provision consideration is given to the expected future costs to be incurred, the timing of
these expected future costs (largely dependent on the life of the well), and the estimated future level of inflation.
The ultimate cost of decommissioning and restoration is uncertain and costs can vary in response to many factors including changes to the
relevant legal requirements, the emergence of new restoration techniques or experience at other wells. 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 level of provisioning required, which would in turn impact future
financial results.
Share-based payments transactions
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 detailed in Note 2(k).
3. Segment reporting
Identification of reportable segments and types of activities
Following the completion of the Victorian gas asset acquisition in the second half of 2017, the Group identified its operating segments to be
Cooper Basin, South-east Australia (based on the nature and geographic location of the assets) and the Corporate and Discontinued operating
segments. This forms the basis that the Group reports internally 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. The comparative disclosures have been restated to be on a consistent basis as the new segments.
Other prospective opportunities outside of these segments are also considered from time to time and, if they are secured, will then be attributed to
the basin where they are located.
The following are the current segments:
Cooper Basin
Exploration and evaluation of oil and gas and production and sale of crude oil in the Company’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 Origin Energy Resources Limited.
South-east Australia
The South-east Australia segment primarily consists of the Sole Gas Project, Manta Gas Project and gas production from the Company’s interest
in the operated Casino Henry and non-operated Minerva 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 Business Unit
The Corporate Business Unit includes the revenue and costs associated with the running of the business and includes items which are not
directly allocable to the other segments.
Discontinued Operations
Discontinued operations consist of the Company’s former interests in Indonesia and Tunisia which have been sold or withdrawn from at
30 June 2017.
91
Notes to the Financial StatementsFor the year ended 30 June 2018 3. Segment reporting continued
Accounting policies and inter-segment transactions
The accounting policies used by the Group in reporting segments internally is the same as those contained in Note 2 to the accounts and in the
prior period.
The following table presents revenue and segment results for reportable segments:
Segments
Cooper
Basin
South-east
Australia
Corporate
Continuing
Operations Total
Discontinued
Operations Total
Consolidated
$’000
$’000
$’000
$’000
$’000
$’000
Year ended 30 June 2018
Revenue
26,602
40,850
Other income and revenue
-
-
Total consolidated revenue
26,602
40,850
-
4,933
4,933
-
(604)
67,452
4,933
72,385
(604)
(2,716)
(16,873)
(2,735)
(44)
(696)
(775)
21,934
(324)
(4,916)
236
34
(2,642)
(16,881)
(1,994)
(11,520)
(850)
31,019
(3,053)
(13,820)
(109)
(2,626)
(2,716)
(44)
-
(775)
21,934
-
(4,916)
-
34
-
(9,712)
-
-
-
-
-
-
-
-
-
-
(324)
-
236
-
(2,642)
-
-
(11,520)
-
-
-
-
(696)
-
-
-
-
-
-
-
(7,169)
(1,994)
-
(850)
12,731
12,731
5,168
18,978
11,046
28,209
(9,921)
28,209
210,810
284,598
482,441
(9,921)
156,897
513,181
35,634
31,019
372,875
816,757
529,121
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
67,452
4,933
72,385
(604)
(2,716)
(16,873)
(2,735)
(44)
(696)
(775)
21,934
(324)
(4,916)
236
34
(2,642)
(16,881)
(1,994)
(11,520)
(850)
31,019
4,781
(8,789)
27,011
372,875
816,757
529,121
Depreciation of property,
plant and equipment
Amortisation of property,
plant and equipment
Amortisation of oil and
gas assets
Accretion on rehabilitation
provision
Accretion on success
fee liability
Impairment
Care & maintenance
Gain on sale of subsidiary
Write-off of fixed asset
Restoration expense
Fair value movement on oil
price derivatives
Fair value adjustment on
success fee
Share based payments
Production expenses
Royalties
Other expenses
Exploration costs written off
Segment result
Income tax
Petroleum Resource
Rent Tax
Net profit/(loss)
Segment liabilities
Segment assets
Non-Current Assets
92
Notes to the Financial StatementsFor the year ended 30 June 2018
3. Segment reporting continued
Segments
Cooper
Basin
South-east
Australia
Corporate
Continuing
Operations Total
Discontinued
Operations Total
Consolidated
$’000
$’000
$’000
$’000
$’000
$’000
Year ended 30 June 2017
Revenue
15,513
19,135
Other income and revenue
-
-
Total consolidated revenue
15,513
19,135
-
-
-
(595)
(2,083)
(7,120)
(92)
(2,420)
34,648
1,614
36,262
(235)
(595)
4,481
-
4,481
(56)
-
39,129
1,614
40,743
(291)
(595)
(9,203)
(59)
(9,262)
Depreciation of property,
plant and equipment
Amortisation of property,
plant and equipment
Amortisation of oil and
gas assets
Accretion on rehabilitation
provision
Accretion on success
fee liability
Impairment
Care & maintenance
Share of loss in associate
Restoration expense
Fair value adjustment on
success fee
Share based payments
Production expenses
Royalties
Gain on sale of subsidiary
Other expenses
Exit provision
Exploration costs written off
Segment result
Income tax
Petroleum Resource
Rent Tax
Net profit/(loss)
Segment liabilities
Segment assets
Non-Current Assets
-
1,614
1,614
(235)
-
-
-
-
-
-
(533)
-
-
(2,272)
-
-
-
-
-
(2,512)
(43)
-
(1,629)
(533)
(1,226)
58
(2,272)
(9,198)
(1,062)
-
-
(1,577)
(7,035)
(43)
-
(1,629)
-
(1,226)
58
-
(3,036)
-
-
-
-
-
-
-
-
-
-
-
-
(6,162)
(1,062)
-
-
-
(1,577)
4,537
4,537
6,526
16,718
12,684
(13,270)
(13,270)
3,124
(14,696)
3,124
163,492
316,006
283,981
(14,696)
33,825
159,920
8,684
(7,035)
203,843
492,644
305,349
-
-
(1,020)
-
-
-
-
(1,780)
(672)
1,395
(360)
(4,031)
(242)
(2,344)
(2,344)
3,754
-
-
2018
$’000
67,452
-
67,452
(2,512)
(43)
(1,020)
(1,629)
(533)
(1,226)
58
(2,272)
(10,978)
(1,734)
1,395
(13,630)
(4,031)
(1,819)
(9,379)
4,665
(7,598)
(12,312)
207,597
492,644
305,349
2017
$’000
34,648
4,481
39,129
Revenue from external customers by geographical location of production
Australia
Indonesia1
Total revenue
Revenue from three customers amounted to $24,365,000, $10,357,000 and $5,084,000 respectively in the South-east Australia segment and
$21,842,000 from one customer in the Cooper Basin segment. In 2017, revenue from two customers amounted to $14,296,000 in the South-east
Australia segment and $15,127,000 in the Cooper Basin segment.
1. Classified as revenue from discontinued operations in the prior year.
93
Notes to the Financial StatementsFor the year ended 30 June 2018
4. Revenues and expenses from continuing operations
Profit before income tax expense includes the following revenues and expenses whose disclosure is relevant in explaining the performance
of the entity:
Revenues from continuing operations
Oil sales
Gas sales
Total revenue from operations
Other revenue
Interest revenue
Gain on movement of consideration receivable
Gain on derecognition of associate
Joint venture fees
Total other revenue
Cost of sales
Production expenses
Royalties
Amortisation of oil and gas assets
Amortisation of property, plant and equipment
Total cost of sales
Finance costs
Accretion of rehabilitation provisions
Accretion of success fee liability
Interest expense
Capitalised interest
Total finance costs
Other expenses
Depreciation of property, plant and equipment
General administration (includes employee benefits and lease payments)
Care and maintenance
Write-off of fixed asset
Restoration expense
Shae of associate’s loss
Fair value adjustment of success fee liability
Fair value movement on oil price derivatives
Realised and unrealised foreign currency translation gain/(loss)
Total other expenses
Employee benefits expense (gross)
Director and employee benefits
Share based payments
Superannuation expense
Total employee benefits expense
Lease payments
Consolidated
2018
$’000
26,602
40,850
67,452
2017
$’000
15,738
18,910
34,648
4,049
1,331
531
353
-
4,933
(16,881)
(1,994)
(16,873)
(2,716)
(38,464)
(2,735)
(44)
(3,394)
3,394
(2,779)
(604)
(14,797)
(775)
(324)
(4,916)
-
34
236
635
-
-
283
1,614
(9,198)
(1,062)
(9,203)
(595)
(20,058)
(2,512)
(43)
-
-
(2,555)
(235)
(15,388)
(1,629)
-
(1,226)
(533)
58
-
(154)
(20,511)
(19,107)
(12,536)
(2,642)
(657)
(15,835)
(8,172)
(2,272)
(440)
(10,884)
Minimum lease payment – operating lease
(839)
(352)
94
Notes to the Financial StatementsFor the year ended 30 June 2018 5. Income tax
The major components of income tax expense are:
Consolidated Statement of Comprehensive Income
Current income tax
Adjustments in respect of prior year income tax
Deferred income tax
Origination and reversal of temporary differences
Over provision in respect of prior year income tax
Income tax benefit
Current royalty tax
Current year
Adjustments in respect of prior year income tax
Deferred royalty tax
Origination and reversal of temporary differences
Total royalty tax expense
Numerical reconciliation between tax expense and pre-tax net profit
Accounting profit/(loss) before tax from continuing operations
Income tax using the domestic corporation tax rate of 30% (2017: 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
Other
Total
Royalty related tax expense
Income tax expense
Income tax recognised in other comprehensive income
Deductible equity costs
Fair value movement on derivative financial instruments
Income tax using the domestic corporation tax rate of 30% (2017: 30%)
Consolidated
2018
$’000
2017
$’000
-
-
5,784
(1,003)
4,781
4,781
(1,372)
1,458
(38)
(38)
4,824
-
4,824
4,786
(6,117)
-
86
(6,117)
(8,875)
(8,875)
(8,789)
31,019
(9,306)
6,044
6,582
(749)
(1,003)
3,107
106
4,781
(8,789)
(4,008)
1,599
(92)
1,507
(1,481)
(1,481)
(7,598)
(7,035)
2,111
-
-
(54)
(38)
2,279
488
4,786
(7,598)
(2,812)
-
(369)
(369)
95
Notes to the Financial StatementsFor the year ended 30 June 2018
5. Income tax continued
Cooper Energy Limited and its 100% owned Australian resident subsidiaries formed a tax consolidated Group. Cooper Energy Limited is 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. Cooper Energy Limited formally notified the Australian Tax Office of its adoption of the tax
consolidation regime when lodging its 30 June 2003 consolidated tax return.
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 2018, there are no unrecognised temporary differences associated with the Group’s investments in subsidiaries or joint ventures,
as the Group has no liability for additional taxation should unremitted earnings be remitted (2017 $nil).
Franking Tax Credits
At 30 June 2018 the parent entity had franking tax credits of $42,856,152 (2017: $42,856,152). The fully franked dividend equivalent is
$142,852,840 (2017 $142,852,840).
PRRT
Cooper Energy Limited has recognised a Deferred Tax Liability for Petroleum Resource Rent Tax (PRRT) of $10,356,000 (2017: $1,481,000)
relating to PRRT on the Company’s producing gas assets. The Company has not recognised a Deferred Tax Asset for PRRT of $39,037,000
(2017: $29,386,000). This is in respect of the Company’s Cooper Basin oil producing assets on the basis that it has a significant level of
undeducted expenditure and nil PRRT payments projected in the future and the Sole Gas Project.
Income Tax Losses
(a) Revenue Losses
Cooper Energy has recognised a Deferred Tax Asset for the year ended 30 June 2018 of $21,612,000 (2017: $16,275,000).
(b) Capital Losses
Cooper Energy has not recognised a Deferred Tax Asset for Australian income tax capital losses of $2,998,458 (2017: $62,272,095) 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 during the year to offset the capital gain generated from the sale of the Orbost Gas Plant and the receipt of funds from exited joint venture
parties for the BMG abandonment.
Consolidated
Statement of Financial
Position
Consolidated Statement
of Comprehensive
Income
2018
$’000
2017
$’000
2018
$’000
2017
$’000
3,583
16,153
4,082
424
-
2,419
(1,164)
325
(15,828)
15,934
11,851
24
38
(308)
38
1,486
325
3,398
-
38
24,242
18,740
(5,411)
5,247
Deferred income tax from corporate tax
Deferred income tax at 30 June relates to the following:
Deferred tax liabilities
Trade and other receivables
Oil and gas assets
Exploration and evaluation
Other
Unrealised currency translation gain
96
Notes to the Financial StatementsFor the year ended 30 June 2018 5. Income tax continued
Deferred tax assets
Property, plant & equipment
Oil and gas assets
Unrealised currency translation gain
Trade and other payables
Provision for employee entitlements
Provisions
Other
Capital raising costs
Tax losses
Deferred tax benefit
Consolidated
Statement of Financial
Position
Consolidated Statement
of Comprehensive
Income
2018
$’000
2017
$’000
2018
$’000
2017
$’000
-
-
-
-
1,823
4,602
3,313
3,226
21,612
34,576
-
-
-
1,199
365
2,488
473
2,255
16,275
23,055
-
-
-
(1,199)
1,459
2,114
3,108
(628)
5,338
10,192
(10)
(1,762)
(2)
1,199
(210)
1,900
(22)
-
8,614
9,707
4,781
14,954
Deferred tax asset from corporate tax
10,334
4,315
Deferred income tax from petroleum resource rent tax
Deferred income tax at 30 June relates to the following:
Deferred tax liabilities
Oil and gas assets
6. Discontinued operations and assets held for sale
Orbost Gas Plant
10,356
1,481
8,875
1,481
The sale of the Orbost Gas Plant to APA Group, originally announced on 27 February 2017, completed on 31 October 2017.
The plant was sold for consideration of $20.0 million to be held in escrow, which will be released to the Company upon satisfaction of certain
conditions; these funds are shown on the balance sheet as a financial asset. Additionally, $24.4 million of costs incurred by the Company in
respect of the Orbost Gas Plant were reimbursed by APA.
On completion, a gain on sale of $21.9 million was recognised in the Consolidated Statement of Comprehensive Income.
Consideration received
Transaction costs
Net consideration received
Value of assets sold
Gain on sale
Indonesia
2018
$’000
44,352
(2,505)
41,847
19,913
21,934
During 2017, the Company executed a share sale agreement with Bass Oil Company Limited (BAS), the Company’s associate, for the sale of its
remaining Indonesian asset, a 55% interest in the Tangai-Sukananti KSO. The Company has agreed to an extension to the settlement terms, with
an interest charge payable by BAS on the deferred balance. A receivable of $2.2 million remains on the balance sheet relating to the deferred
consideration receivable from Bass Oil Company Limited which will be fully received by June 2019.
97
Notes to the Financial StatementsFor the year ended 30 June 2018 7. Earnings per share
Basic earnings per share amounts are calculated by dividing net profit for the year attributable to ordinary equity holders of the parent by the
weighted average of ordinary shares outstanding during the year.
Diluted earnings per share amounts are calculated by dividing the net profit attributable to ordinary equity holders of the parent by the weighted
average number of ordinary shares outstanding during the year plus the weighted average number of ordinary shares that would be issued on the
conversion of all the dilutive potential options into ordinary shares. At 30 June 2018 there exists 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 prior 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.
The following reflects the income and share data used in the basic and diluted earnings per share computations:
Net profit/(loss) attributable to ordinary equity holders of the parent from continuing operations
Weighted average number of ordinary shares for basic earnings per share
Weighted average number of ordinary shares adjusted for the effect of dilution1
Basic earnings per share for the period (cents per share)
Diluted earnings per share for the period (cents per share)
Net profit/(loss) attributable to ordinary equity holders of the parent from continuing and
discontinued operations
Weighted average number of ordinary shares for basic earnings per share
Weighted average number of ordinary shares adjusted for the effect of dilution1
Basic earnings per share for the period (cents per share)
Diluted earnings per share for the period (cents per share)
Consolidated
2018
$’000
27,011
2018
Thousands
1,506,880
1,529,450
1.8
1.8
2017
$’000
(9,847)
2017
Thousands
683,255
683,255
(1.4)
(1.4)
Consolidated
2018
$’000
2017
$’000
27,011
(12,312)
2018
Thousands
1,506,880
1,529,450
1.8
1.8
2017
Thousands
683,255
683,255
(1.8)
(1.8)
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.
1. The weighted average number of potentially dilutive shares at 30 June 2018 is 1,529,450,000 (2017: 705,291,000), including performance
rights and share appreciation rights that have not been achieved and vested at the end of the financial year.
98
Notes to the Financial StatementsFor the year ended 30 June 2018 8. Cash and cash equivalents and term deposits
Current Assets
Cash at bank and in hand
Short term deposits at banks (i)
Total cash and cash equivalents
Non-Current Assets
Term deposits at bank (ii)
Consolidated
2018
$’000
236,907
-
2017
$’000
49,425
98,000
236,907
147,425
16
41
(i) Short term deposits at banks are in Australian dollars and are generally for periods of three months or less and earn interest at money market
interest rates. There were no term deposits with a maturity greater than 3 months.
(ii) The carrying value of term deposits approximates their fair value.
Reconciliation of net profit after tax to net cash flows from operating activities
Net profit/(loss) for the Year
Adjustments for:
Amortisation of oil and gas assets
Amortisation of property, plant and equipment
Depreciation of property, plant and equipment
Exploration and evaluation written off
Exit provision
Other non-cash movement
Impairment of Non-Current Assets
Gain on sale of subsidiary
Write-off of fixed assets
Gain on derecognition of associate
Share of loss in associate
Share based payments
Finance cost
Restoration expense
Fair value adjustment of success fee liability
Gain on movement of consideration receivable
Unrealised foreign currency translation (gain)/loss
(Increase)/decrease in trade and other receivables
(Increase)/decrease in prepayments
(Decrease)/increase in deferred taxes
(Decrease)/increase in trade and other payables
(Decrease)/increase in provisions
(Increase)/decrease in held for sale assets
Net cash from operating activities
Consolidated
2018
$’000
2017
$’000
27,011
(12,312)
16,873
2,716
604
850
153
1,841
696
(21,934)
324
(353)
-
2,642
2,779
4,916
(34)
(531)
(1,385)
(11,544)
52
2,856
5,463
(12,135)
358
22,218
2017
$’000
Cash Flows
$’000
Other
$’000
9,262
595
291
1,819
(3,703)
-
1,020
(1,395)
-
-
533
2,272
2,555
1,226
(58)
-
57
(10,474)
(507)
(5,010)
13,216
559
4,132
4,078
2018
$’000
Reconciliation of liabilities arising from financing activities
Interest bearing loans and borrowings
Total liabilities from financing activities
-
-
125,865
125,865
(8,942)
(8,942)
116,923
116,923
99
Notes to the Financial StatementsFor the year ended 30 June 2018 9. Trade and other receivables
Current Assets
Trade receivables (i)
Accrued revenue
Related party receivable – joint arrangements
Interest receivable
Consolidated
2018
$’000
12,604
12,298
2,067
361
27,330
2017
$’000
2,813
7,855
-
210
10,878
(i) Trade receivables are non-interest bearing and are generally on 30-90 days terms. There are no past due or impaired trade receivables and
none that have a history of past default.
Non-Current Assets
Trade receivables
Consideration receivable
10. Prepayments
Current Assets
Bank facility fee
Insurance
Other
Non-Current Assets
Insurance
11. Equity instruments
Shares at fair value
A reconciliation of the movement during the year is as follows:-
Opening balance
Gain on derecognition of associate
Fair value movement
Closing balance
Consolidated
2018
$’000
11
145
156
Consolidated
2018
$’000
-
1,761
1,000
2,761
-
-
Consolidated
2018
$’000
2,241
658
353
1,230
2,241
2017
$’000
1,739
1,258
2,997
2017
$’000
79
1,787
36
1,902
911
911
2017
$’000
658
790
-
(132)
658
The equity investments consist of two investments and the Group has received no dividends throughout the financial year.
100
Notes to the Financial StatementsFor the year ended 30 June 2018 12. Oil and Gas assets
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at 1 July
Additions
Transferred from exploration and evaluation
Gas assets acquired
Amortisation
Carrying amount at 30 June
Cost
Accumulated amortisation & impairment
13. Impairment
Impairment of exploration and evaluation assets
Cooper Basin Northern Licenses
Total
Consolidated
2018
$’000
69,402
192,468
149,635
-
(16,873)
394,632
447,631
(52,999)
394,632
2017
$’000
5,385
6,530
-
66,690
(9,203)
69,402
105,528
(36,126)
69,402
Consolidated
2018
$’000
696
696
2017
$’000
-
-
In accordance with the Group’s accounting policies and procedures, the Group performs its impairment testing bi-annually.
Exploration and evaluation impairment
During the financial year the Company’s exploration assets were assessed for impairment indicators in accordance with AASB 6. Impairment
losses were recognised in respect of the Cooper Basin Northern Licenses during the 2018 financial year as a result of no significant work planned
in the future and no current commercial development potential.
Oil and gas asset impairment
At year-end the Company’s oil and gas assets were assessed for impairment indicators in accordance with AASB 136. Following this assessment,
notwithstanding that impairment indicators were present, no impairment was recognised on oil and gas assets during the 2018 financial year.
14. Property, plant and equipment
Reconciliation of carrying amounts at beginning and end of period:
Carrying amount at 1 July
Assets acquired
Additions
Disposals/written off
Depreciation
Amortisation
Transferred to assets held for sale
Carrying amount at 30 June
Cost
Accumulated depreciation & amortisation
Consolidated
2018
$’000
3,694
-
2,822
(332)
(604)
(2,716)
-
2,864
8,407
(5,543)
2,864
2017
$’000
708
3,743
2,159
(1)
(235)
(595)
(2,085)
3,694
5,917
(2,223)
3,694
101
Notes to the Financial StatementsFor the year ended 30 June 2018 15. Exploration and evaluation
Reconciliations of the carrying amounts of capitalised exploration at the beginning and end of the
financial year are set out below:
Carrying amount at 1 July
Additions
Exploration acquired
Unsuccessful exploration wells written off (i)
Impairment
Transfer to oil and gas assets
Carrying amount at 30 June (ii)
Consolidated
2018
$’000
2017
$’000
223,331
110,976
26,582
-
(850)
(696)
(149,635)
29,094
84,061
(800)
-
-
98,732
223,331
(i) Exploration write offs relate to exploration wells that were plugged and abandoned as unsuccessful during the year.
(ii) Recoverability is dependent on the successful development and commercial exploration or sale of the respective areas of interest.
16. Trade and other payables
Trade payables (i)
Hedge payable
Contingent bonus consideration (ii)
Accruals (iii)
Deferred lease incentive
Related party payables – joint arrangements (iv)
Consolidated
2018
$’000
14,159
-
-
39,342
1,459
54,960
4,255
59,215
(i) Trade and other payables are non-interest bearing and are normally settled on 30-90 day terms.
(ii) Contingent bonus consideration was payable to Santos Limited on final investment decision on the Sole Gas Project.
(iii) Accruals include capital accruals on projects.
(iv) Related party payables are accrued expenditure incurred on joint arrangements.
2017
$’000
5,110
22
20,000
29,366
-
54,498
4,022
58,520
2017
$’000
14,584
3,754
850
-
Consolidated
2018
$’000
67,651
3,907
730
1,524
73,812
19,188
17. Provisions
Current Liabilities
Restoration provision
Exit penalty provision
Employee provisions
Other provisions
102
Notes to the Financial StatementsFor the year ended 30 June 2018 17. Provisions continued
Non-Current Liabilities
Long service leave provision
Restoration provisions
Movement in carrying amount of the current restoration provision:
Carrying amount at 1 July
Restoration provision assumed (i)
Restoration expenditure incurred
Transferred from non-current provisions
Impact of changes in restoration assumptions (ii)
Carrying amount at 30 June
Movement in carrying amount of the non-current restoration provision:
Carrying amount at 1 July
Transferred to held for sale
Restoration expenditure incurred
New provisions recognised (iii)
Transferred to current provisions
Provision through asset acquisition
Increase through accretion
Impact of changes in restoration assumptions (ii)
Carrying amount at 30 June
Consolidated
2018
$’000
610
106,070
106,680
14,584
48,082
(16,367)
21,271
81
2017
$’000
365
99,437
99,802
-
-
-
14,584
-
67,651
14,584
99,437
-
-
13,608
65,202
(9,980)
(155)
-
(21,271)
(14,584)
-
2,649
11,647
106,070
71,687
2,512
(15,245)
99,437
(i) Relates to the Company’s increased share of the BMG restoration provision on settlement with exited parties as outlined in note 2 a.
(ii) Changes in restoration assumptions results from a change in the discount rate and changes in gross cost assumptions.
(iii) New provisions recognised is in respect of restoration provisions arising from the drilling of the Sole-3 and Sole-4 wells.
The restoration provision is the present value of the Group’s share of the estimated cost to restore operating locations. 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. However, actual restoration costs will ultimately depend upon future market prices for the necessary
decommissioning works required that will reflect market conditions and the condition of the site at the time of the restoration. Furthermore, the
timing of restoration is likely to depend on when the fields cease to produce at economically viable rates. This, in turn, will depend upon future oil
and gas prices, which are inherently uncertain.
The discount rate used in the calculation of the provisions as at 30 June 2018 ranged from 2.00% to 2.70% (2017: 2.41%) reflecting a risk free
rate that aligns to the date of restoration obligations.
103
Notes to the Financial StatementsFor the year ended 30 June 2018 18. Interest bearing loans and borrowings
Interest bearing loans and borrowings
Non-current (bank debt)
Total interest bearing loans and borrowings
Net of capitalised transaction costs of $8.9 million.
Consolidated
2018
$’000
2017
$’000
116,923
116,923
-
-
In August 2017, Cooper Energy negotiated a A$250 million senior secured Reserve Based Lending Facility, principally to fund the Sole Gas
Project, and a senior secured $15 million working capital facility.
Borrowings are recognised initially at fair value. 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 then amortised on a straight-line basis 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 received
at balance date, is reflected in the balance sheet as a payable.
A summary of the Group’s secured facilities is included below.
Facility
Currency
Limit1
Reserve Based Lending Facility
Australian dollars
$250.0 million (2017: Nil)
Utilised amount
$125.9 million (2017: Nil)
Accounting balance
$116.9 million
Effective interest rate
6.36%
Maturity
2021 – 2024
1. Of the facility limit of $250.0 million, $224.0 million is currently available.
Facility
Currency
Limit
Utilised amount1
Accounting balance
Effective interest rate
Working Capital Facility
Australian Dollars
$15.0 million
Nil (2017: Nil)
Nil
Nil
Maturity
Revolving facility
1. As at 30 June 2018, $945,825 has been utilised by way of bank guarantees.
19. Contributed equity and reserves
Share capital
Ordinary shares
Issued and fully paid
104
2018
$’000
2017
$’000
471,837
343,161
Notes to the Financial StatementsFor the year ended 30 June 2018 19. Contributed equity and reserves continued
Capital raising
During the period the Group raised $127.8 million (net of costs and tax of $6.2 million) through institutional placements and entitlement offers,
456,221,699 new ordinary shares were issued.
Fully paid ordinary shares carry one vote per share and carry the right to dividends.
Movement in ordinary shares on issue
At 1 July
Equity issue
Issuance of shares to contractors
Issuance of shares for performance rights & share appreciation rights
2018
2017
Thousands
$’000
Thousands
$’000
1,140,551
343,161
456,222
127,803
-
4,306
-
873
435,186
699,662
630
5,073
137,558
203,940
223
1,440
1,601,079
471,837
1,140,551
343,161
At 30 June
Reserves
Consolidated
At 1 July 2016
Other comprehensive
income/(expenditure)
Transferred to
issued capital
Share-based payments
At 30 June 2017
(541)
Other comprehensive
income/(expenditure)
Transferred to issued
capital
Share-based payments
-
-
-
At 30 June 2018
(541)
Nature and purpose of reserves
Consolidation reserve
Consolidation
reserve
$’000
Foreign
currency
translation
reserve
$’000
Share
based
payment
reserve
$’000
Option
premium
reserve
$’000
Cash flow
hedge
reserve
$’000
Equity
instrument
reserve
$’000
Total
$’000
(541)
1,132
7,208
25
(700)
(553)
6,571
-
-
-
(1,132)
-
-
-
-
-
-
-
-
(1,440)
2,049
7,817
-
(873)
2,642
9,586
-
-
-
25
-
-
-
861
(132)
(403)
-
-
161
149
-
-
-
-
(685)
1,230
-
-
(1,440)
2,049
6,777
1,379
(873)
2,642
9,925
25
310
545
The reserve comprises the premium paid on acquisition of minority shareholdings in a controlled entity.
Foreign currency translation reserve
This reserve is used to record the value of foreign currency movements on retranslation of the net assets of the US dollar functional currency
subsidiary.
Share based payment reserve
This reserve is used to record the value of equity benefits provided to employees 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 mark to market movement in the value of shares held in companies listed on a public exchange. Items in this
reserve are never recycled through profit or loss.
105
Notes to the Financial StatementsFor the year ended 30 June 2018 19. Contributed equity and reserves continued
Accumulated Losses
Movement in accumulated losses:
Balance at 1 July
Net profit/(loss) for the year
Balance at 30 June
Capital Management
Consolidated
2018
$’000
2017
$’000
(64,891)
27,011
(37,880)
(52,579)
(12,312)
(64,891)
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. 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. The Group currently has utilised $125.9 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 years ended 30 June 2018 and 30 June 2017.
20. Financial risk management objectives and policies
The Group’s principal financial instruments comprise cash and short term deposits, receivables, equity investments, payables and borrowings.
Details of the significant accounting policies and methods adopted, including criteria for recognition, the basis of measurement and the basis on
which income and expenses are recognised in respect of each financial instrument are disclosed in Note 2 to the financial statements.
Other financial assets
Current
Cash held in escrow
Non-Current
Escrow proceeds receivable
Other financial liabilities
Current
Derivative financial instruments
Derivative financial instruments designated in a hedge relationship
Non-Current
Success fee financial liability
Derivative financial instruments designated in a hedge relationship
106
Consolidated
2018
$’000
2017
$’000
20,171
20,171
20,146
20,146
236
355
591
3,054
177
3,231
-
-
-
-
-
114
114
3,044
-
3,044
Notes to the Financial StatementsFor the year ended 30 June 2018 20. Financial risk management objectives and policies continued
Movement in carrying amount of the success fee financial liability:
Carrying amount at 1 July
Finance cost
Fair value adjustment
Carrying amount at 30 June
Fair value hierarchy
Consolidated
2018
$’000
2017
$’000
3,044
3,059
44
(34)
43
(58)
3,054
3,044
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 Company determines whether transfers have occurred between
levels in the hierarchy by re-assessing categorisation (based on the lowest level input that is significant to the fair value measurement as a whole)
at the end of each reporting period.
Set out below is an overview of financial instruments held by the Company, with a comparison of the carrying amounts and fair values as at 30
June 2018:
Carrying amount
Fair value
Level
2018
$’000
2017
$’000
2018
$’000
2017
$’000
Consolidated
Financial assets
Trade and other receivables
Equity instruments
Cash held in escrow
Escrow proceeds receivable
Financial liabilities
Trade and other payables
Success fee financial liability
Derivative financial instruments
Derivative financial instruments designated in a
hedge relationship
Interest bearing loans and borrowings
2
1
2
2
2
3
2
2
2
27,330
13,875
27,330
13,875
2,241
20,171
20,146
59,215
3,054
236
532
658
-
-
58,520
3,044
-
114
2,241
20,171
20,146
59,215
3,054
236
532
116,923
-
101,842
The following summarises the significant methods and assumptions used in estimating the fair values of financial instruments:
Equity instruments
Equity instruments are measured at fair value through other comprehensive income. The fair value of equity instruments is 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.
658
-
-
58,520
3,044
-
114
-
107
Notes to the Financial StatementsFor the year ended 30 June 2018 20. Financial risk management objectives and policies continued
Cash held in escrow and escrow proceeds receivable
During the period, the Company completed the sale of Orbost Gas Plant to APA Group. A portion of proceeds from the sale is held in escrow, to be
released upon certain conditions being satisfied. Additional funds are held in escrow for payments to be made in connection with the Company’s
2018 drilling campaign. Amounts held in escrow are measured at amortised cost and held at the estimated realisable value in the 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 the fair value is obtained from third party valuation reports.
Derivative financial instruments
Commodity derivatives are also used to manage the Group’s exposure to changes in oil prices and are measured at fair value through profit and
loss. The Group has elected not to apply hedge accounting to its commodity derivatives entered into during the 2018 financial year. The use of
derivative financial instruments is subject to a set of policies, procedures and limits approved by the Board of Directors. The Group does not trade
in derivative financial instruments for speculative purposes.
Success fee financial liability
The success fee liability is the fair value of the Group’s liability to pay a $5,000,000 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 valuation inputs for the
success fee financial liability includes: a probability of 37% that no payment is made and a probability of 63% the payment is made in 2023. The
discount rate used in the calculation of the liability as at 30 June 2018 equalled 2.70% (June 2017: 2.41%). 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.
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
Company has established a Risk and Sustainability Committee from 1 July 2017.
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.
It is, and has been, throughout the period under review, the Board’s policy that no speculative trading in financial instruments be undertaken.
The primary responsibility for the identification and control of financial risks rests with the Managing Director and the Chief Financial Officer,
under the authority of the Board. The Board is apprised of these and other risks at Board meetings and agrees any policies that may be
implemented to manage any of the risks identified below.
Market risk
Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market prices. Market
risk comprises three types of risk: foreign currency risk, commodity price risk and interest rate risk. Financial instruments affected by market risk
include deposits, trade receivables, trade payables and accrued liabilities.
The sensitivity analyses in the following sections relate to the position as at 30 June 2018 and 30 June 2017.
The sensitivity analyses have been prepared on the basis that the amount of the financial instruments in foreign currencies is all constant. 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.
The analyses exclude the impact of movements in market variables on the carrying value of provisions.
The following assumptions have been made in calculating the sensitivity analyses:
• The statement of financial position sensitivity relates to US-denominated trade receivables
• The sensitivity of the relevant profit before tax item and/or equity is the effect of the assumed changes in respective market risks. This is based
on the financial assets and financial liabilities held at 30 June 2018 and 30 June 2017
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 the Group’s functional currency of Australian dollars.
The majority of costs related to the Sole Gas Project 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.
108
Notes to the Financial StatementsFor the year ended 30 June 2018 20. Financial risk management objectives and policies continued
Currently the Group has no foreign exchange hedge programmes in place. The Chief Financial Officer 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 (current and non-current)
Cash held in escrow
Consolidated
2018
$’000
5,403
7,852
20,171
2017
$’000
2,680
4,011
-
The following table summarises the sensitivity of financial instruments held at the year end, to movements in the exchange rates for the Australian
dollar to the foreign currency, with all other variables held constant.
If the Australian dollar were higher at the balance date by 10%
If the Australian dollar were lower at the balance date by 10%
b) Commodity price risk
Impact on after tax profit
2018
$’000
(1,205)
1,473
2017
$’000
(608)
743
The Group uses oil price options to manage some of its transaction exposures. Options entered into in the 2018 financial year 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. Certain options entered into prior to the 2018 financial year were designated as cash flow hedges.
The following table shows the effect of price changes in oil on the Group’s provisional sales excluding the effect of hedging.
Commodity price risk arises from the sale of oil denominated in US dollars. The Group has provisional sales at 30 June 2018 of $7,852,230
(2017: $4,011,293).
If the Brent Average price were higher at the balance date by 10%
If the Brent Average price were lower at the balance date by 10%
c) Interest rate risk
The Group has borrowings of $116,922,982 at 30 June 2018 (2017: $ nil). Interest on borrowings are capitalised.
The Group has interest bearing deposits of $ nil (2017: $98,000,000).
If the interest rate were 1% rate higher at the balance date
If the interest rate were 1% rate lower at the balance date
Credit risk
Impact on after tax profit
2018
$’000
901
(901)
2017
$’000
461
(461)
Impact on after tax profit
2018
$’000
-
-
2017
$’000
314
(314)
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. 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. Exposure at balance date is addressed in each applicable note.
The Group managed its credit risk with interest rate swaps, designated as cash flow hedges, refer to note 21.
The Group trades only with recognised creditworthy third parties. The Group has had no exposure to bad debts.
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.
109
Notes to the Financial StatementsFor the year ended 30 June 2018 20. Financial risk management objectives and policies continued
Cash and cash equivalents and term deposits are held at three financial institutions that have a Standard & Poor’s A credit rating or better. Trade
receivables are settled on 30 to 90 day terms.
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 Company’s financial liabilities based on contractual undiscounted payments:
At 30 June 2018
Trade and other payables
Interest bearing loans and borrowings
Financial liabilities
Derivative financial liabilities
Derivative financial liabilities designated in
a hedge relationship
At 30 June 2017
Trade and other payables
Financial liabilities
Derivative financial liabilities designated in
a hedge relationship
Share price risk
Less than
3 months
$’000
3 to 12
months
$’000
1 to 5
years
$’000
Greater than
5 years
$’000
Total
$’000
57,756
1,967
-
91
-
-
-
-
57,756
5,902
56,747
104,141
168,757
-
145
355
5,000
-
177
-
-
-
5,000
236
532
59,814
6,402
61,924
104,141
232,281
58,520
-
57
58,577
-
-
57
57
-
5,000
-
5,000
-
-
-
-
58,520
5,000
114
63,634
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.
If the share price were 10% higher at the balance date
If the share price were 10% lower at the balance date
21. Hedge accounting
Impact on revaluation reserve
2018
$’000
223
(224)
2017
$’000
66
(66)
The Company 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.
In the prior period the Company designated its oil price options in a hedge relationship. These options matured in December 2017 with
subsequent oil price options entered into during the 2018 financial year not being designated in a hedge relationship.
110
Notes to the Financial StatementsFor the year ended 30 June 2018 21. Hedge accounting continued
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 Company’s reserve base lending facility. These forecast transactions are highly probable, and they
comprise 95% of the Company’s total expected interest payments June 2020.
Carrying amount
$0.5 million (2017: Nil)
Notional value
Hedge cover
Maturity date
Average hedged rate
$118.4 million (2017: Nil)
94%
June 2020
6.43%
The fair value of the swaps vary based on the level of sales and changes in forward rates.
Fair value of oil price options
Fair value of interest rate swaps
30 June 2018
30 June 2017
Assets
$’000
Liabilities
$’000
Assets
$’000
Liabilities
$’000
-
-
-
532
-
-
114
-
The terms of the interest rate swaps match the terms of the expected highly probable forecast interest payments.
During the financial year, $0.3 million was reclassified from other comprehensive income (OCI) to capitalised borrowing costs on the balance
sheet in respect of realised hedge settlements.
The cash flow hedges of the expected future interest payments were assessed to be highly effective and a net unrealised loss of $0.5 million and a
tax expense of $0.1 million relating to the hedging instrument are included in OCI.
The amounts retained in OCI at 30 June 2018 are expected to mature and impact the statement of profit or loss during the 2019 and 2020
financial year.
22. Commitments and contingencies
Operating lease commitments under non-cancellable office lease not provided for in the financial
statements and payable:
Within one year
After one year but not more than five years
After more than five years
Total minimum lease payments
The Parent entity leases an office in Adelaide and Perth from which it conducts its operations.
Exploration capital commitments not provided in the financial statements and payable:
Within one year (i)
After one year but not more than five years
After more than five years
Total minimum lease payments
Consolidated
2018
$’000
2017
$’000
888
2,826
1,246
4,960
5,776
20,130
-
255
-
-
255
14,600
30
-
25,906
14,630
(i) The joint venture has applied for a revision to the work schedule that is currently with the minister for approval.
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 2018 the Parent entity has bank guarantees for $945,825 (2017: $160,512). These guarantees are in relation to performance
bonds on exploration permits and guarantees on office leases.
111
Notes to the Financial StatementsFor the year ended 30 June 2018 23. Interests in joint arrangements
The Group has interests in a number of joint arrangements which are classified as joint operations. These joint operations are involved
in the exploration and/or production of oil in Australia. The Group has the following interests in joint arrangements in the following
major areas:
Joint Arrangements in which Cooper Energy Limited is not the operator/manager
Australia
PEL 90K
PEL 93*
PRL 237
PEL 100
PRL 183-190
(Formerly PEL 110)
PEL 494
PEP 150
PEP 168
PEP 171
PRL 32
PRL 85-104*
(Formerly PEL 92)
*Includes associated PPLs
Oil and gas exploration
Oil and gas exploration and production
Oil and gas exploration
Oil and gas exploration
Oil and gas exploration
Oil and gas exploration
Oil and gas exploration
Oil and gas exploration
Oil and gas exploration
Oil and gas exploration
Oil and gas exploration and production
Ownership Interest
2018
2017
25%
30%
20%
25%
30%
-
19.165%
19.165%
20%
30%
20%
50%
25%
30%
25%
20%
30%
20%
50%
25%
30%
25%
It is noted that the Victorian gas assets acquired in the 2017 financial year do not meet the definition of joint arrangements and as such
are not included in this note.
24. Related parties
The Group has a related party relationship with its subsidiaries, its joint arrangements (see Note 23) and with its key management
personnel (refer to disclosure for key management personnel below).
Key management personnel disclosures
The following were key management personnel of the Group at any time during the reporting period and unless otherwise indicated were
key management personnel for the entire period.
Non-Executive Directors
Mr J. Conde AO (Chairman)
Ms E. Donaghey1
Mr H. Gordon
Mr J. Schneider
Ms A. Williams
Executives at year end
Executive Directors
Mr D. Maxwell
Mr D. Clegg (General Manager Development)
Ms A. Evans (Company Secretary and Legal Counsel)
Mr E. Glavas (General Manager Commercial and Business Development)
Mr M. Jacobsen (General Manager Projects)
Mr I. MacDougall (General Manager Operations)
Ms V. Suttell (Chief Financial Officer)
Mr A. Thomas (General Manager Exploration & Subsurface)
1. Ms Donaghey was appointed a Non-executive Director of the Company effective from 25 June 2018.
112
Notes to the Financial StatementsFor the year ended 30 June 2018 24. Related parties continued
The key management personnel’s remuneration included in General Administration (see Note 4) is as follows:
Short-term benefits
Other long-term benefits
Post-employment benefits
Performance Rights and Share Appreciation Rights
Termination benefits
Total
Subsidiaries
Consolidated
2018
$
2017
$
5,905,751
4,355,038
108,807
220,058
94,811
183,275
1,825,974
1,395,760
-
283,371
8,060,590
6,312,255
The Group 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
Coper Energy (Australia) Pty Ltd
Cooper Energy (PBF) Pty Ltd
Cooper Energy (PB Pipeline) 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 (PBGP) 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
Equity interest
2018
%
2017
%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
-1
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
1. Company was divested and sold to APA Group as part of the sale of the Orbost Gas Plant
Joint arrangements
During the reporting period, the Group provided geological and technical services to joint arrangements it manages at a cost of $nil (2017:
$1,454,000). At the end of the financial period, nothing was outstanding for these services (2017: $nil).
An impairment assessment is undertaken each financial year of related party receivables with reference to the lifetime expected credit loss model.
Where there is evidence that a related party receivable is impaired the Group recognises an allowance for the impairment loss.
113
Notes to the Financial StatementsFor the year ended 30 June 2018 25. Share based payment plans
There are two share based payment plans in place at 30 June 2018. On 12 November 2015 shareholders of Cooper Energy approved the
second 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.
Testing of the performance rights and share appreciation rights will occur once over the performance period and if required 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 a weighted basket
of absolute total shareholder returns of 12 peer companies listed on the Australian Stock 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.
Rights that do not qualify for vesting in the third year can be carried forward to the following year for retesting of vesting eligibility. There
are no participating rights or entitlements inherent in the rights and holders will not be entitled to participate in new issues of capital
offered to shareholders during the period of the rights. All rights are settled by physical delivery of shares.
Information with respect to the number of performance rights and share appreciation rights granted to employees is as follows:
Date Granted
Number of share
appreciation rights
(SARs) granted
Number of
performance
rights granted
15 December 2015
22,278,100
21 December 2016
8 December 2017
9,841,875
15,898,978
7,892,812
3,810,503
6,330,443
The number of performance rights held by employees is as follows:
Average share
price at
commencement
date of grant
Average
contractual life
of rights at grant
date in years
Remaining life of
rights in years
$0.175
$0.298
$0.310
3
3
3
0.5
1.5
2.5
Balance at beginning of year
- granted
- vested
- expired and not exercised
- forfeited following employee termination
Balance at end of year
Achieved at end of year
The number of share appreciation rights held by employees is as follows:
Balance at beginning of year
- granted
- vested
- expired and not exercised
- forfeited following employee termination
Balance at end of year
Achieved at end of year
Number of Rights
2018
2017
10,994,298
6,330,443
-
-
-
7,892,812
3,810,503
(233,975)
-
(475,042)
17,324,741
10,994,298
-
-
Number of Rights
2018
2017
30,118,716
22,278,100
15,898,978
-
-
-
9,841,875
(660,415)
-
(1,340,844)
46,017,694
30,118,716
-
-
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.
114
Notes to the Financial StatementsFor the year ended 30 June 2018 25. Share based payment plans continued
Share Appreciation Rights Fair value assumptions
Fair value at measurement date
Share price
Risk free interest rate
Expected volatility
Dividend yield
Performance Rights Fair value assumptions
Fair value at measurement date
Share price
Risk free interest rate
Expected volatility
Dividend yield
2011 Employee Performance Rights Plan
15 December
2015
21 December
2016
6.2 cents
17.5 cents
1.95%
50%
0%
15.1 cents
29.78 cents
1.575%
56%
0%
15 December
2015
21 December
2016
13.1 cents
16.5 cents
2.13%
53%
0%
28.3 cents
34.5 cents
1.88%
56%
0%
8 December
2017
12.4 cents
29.5 cents
1.94%
56%
0%
8 December
2017
22.4 cents
29.5 cents
1.94%
56%
0%
On 16 December 2011 shareholders of Cooper Energy approved the establishment of an Employee Performance Rights Plan (2011 Plan)
whereby the Board can, subject to certain conditions, issue performance rights to employees to acquire shares in the parent entity.
No issues of performance rights under the 2011 Plan were made during the financial year.
Testing of the performance rights will be in three equal tranches over the term of the right to be determined in the fourth calendar quartile of each
year. At the end of the three year measurement period, those rights that were tested and achieved will vest.
The vesting test is two parts. Up to 25% of the eligible rights to be tested are determined from the absolute total shareholder return of Cooper
Energy’s share price against its own share price at the date of the grant of the right. If the return is less than 5% no rights will vest. If the return is
between 5% and 25% the rights that will vest will be between 6.25% and 12.5% of the eligible rights. If the return is greater than 25% up to 25%
of the eligible rights will vest.
The second part is for the remaining 75% of the eligible rights to vest and is determined from the absolute total shareholder return of Cooper
Energy’s share price ranked against a weighted basket of absolute total shareholder returns of peer companies listed on the Australian Stock
Exchange. If Cooper Energy’s ranking is lower than 6 out of 9 of peer companies no rights will vest. If the ranking is 5th 50% of the eligible rights
will vest. If Cooper Energy is ranked 3rd or 4th, prorate 50% to 100% of the eligible rights will vest and if it ranks 1st or 2nd, 100% of the eligible
rights will vest.
Rights that do not qualify for vesting in any one year can be carried forward to the following year for testing of vesting eligibility. 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.
The number of performance rights held by employees is as follows:
Balance at beginning of year
- granted
- vested
- expired and not exercised
- forfeited following employee termination
Balance at end of year
Achieved at end of year
Number of rights
2018
Number of rights
2017
5,300,196
11,167,070
-
-
(3,975,157)
(4,535,319)
(1,325,039)
-
-
-
(886,918)
(444,637)
5,300,196
2,650,106
The weighted average price of shares vested during the financial year was $0.30 per share.
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.
115
Notes to the Financial StatementsFor the year ended 30 June 2018 26. Auditors remuneration
The auditor of Cooper Energy Limited is Ernst & Young
Amounts received or due and receivable by Ernst & Young Australia for:
Auditing and review of financial reports of the entity and the consolidated Group
Taxation and other services
Services in relation to one off transactions
27. Parent entity information
Information relating to Cooper Energy Limited
Current Assets
Total Assets
Current Liabilities
Total Liabilities
Issued capital
Accumulated loss
Option premium reserve
Cash flow hedge reserve
Equity instruments reserve
Share based payment reserve
Total shareholders’ equity
Profit/(Loss) of the parent entity
Consolidated
2018
$
2017
$
330,000
79,702
92,485
217,259
65,000
-
502,187
282,259
2018
$’000
2017
$’000
416,213
700,530
145,306
227,749
471,837
155,552
436,960
61,308
111,539
343,161
(30,524)
(33,980)
25
310
(869)
9,586
450,365
22,416
25
161
(685)
7,818
316,500
(13,415)
Total comprehensive income/(loss) of the parent entity
(35)
729
Commitments and Contingencies
Operating lease commitments under non-cancellable office lease not provided for in the financial
statements and payable:
Within one year
After one year but not more than five years
After more than five years
Total minimum lease payments
28. Events after the reporting period
Sole-3 flow-back
888
2,826
1,246
4,960
255
-
-
255
On 6 July 2018, the Company announced that Sole-3 is being shut-in for future connection after successful performance of clean-up and flow
back operations.
Debt drawdown
On 23 July 2018, the Company utilised a further $25.7 million of its Reserve Base Loan Facility.
Sole-4 flow-back
On 6 August 2018, the Company announced that Sole-4 is being shut-in for future connection after successful performance of clean-up and flow
back operations.
116
Notes to the Financial StatementsFor the year ended 30 June 2018 Directors’ Declaration
In accordance with a resolution of the Directors of Cooper Energy Limited, I state that:
In the opinion of the Directors:
(a) the financial statements and notes of the consolidated entity are in accordance with the Corporations Act 2001, including:
(i) giving a true and fair view of the consolidated entity’s financial position as at 30 June 2018 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 Note 2b;
(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;
and
(d) 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 2018.
Signed in accordance with a resolution of the Directors.
Mr John C. Conde AO
Chairman
13 August 2018
Mr David P. Maxwell
Managing Director
117
Ernst & Young
121 King William Street
Adelaide SA 5000 Australia
GPO Box 1271 Adelaide SA 5001
Tel: +61 8 8417 1600
Fax: +61 8 8417 1775
ey.com/au
Independent Auditor’s Report to the Members of Cooper Energy Limited
Report on the Audit of the Financial Report
Opinion
We have audited the financial report of Cooper Energy Limited (the Company) and its subsidiaries
(collectively the Group), which comprises the consolidated statement of financial position as at 30
June 2018, consolidated statement of comprehensive income, consolidated statement of changes in
equity and consolidated statement of cash flows for the year then ended, notes to the financial
statements, including a summary of significant accounting policies, and the directors declaration.
In our opinion, the accompanying financial report of the Group is in accordance with the Corporations
Act 2001, including:
a)
b)
giving a true and fair view of the consolidated financial position of the Group as at 30 June
2018 and of its consolidated financial performance for the year ended on that date; and
complying with Australian Accounting Standards and the Corporations Regulations 2001.
Basis for Opinion
We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under
those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial
Report section of our report. We are independent of the Group in accordance with the auditor
independence requirements of the Corporations Act 2001 and the ethical requirements of the
Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics for Professional
Accountants (the Code) that are relevant to our audit of the financial report in Australia. We have also
fulfilled our other ethical responsibilities in accordance with the Code.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis
for our opinion.
Key Audit Matters
Key audit matters are those matters that, in our professional judgement, were of most significance in
our audit of the financial report of the current year. These matters were addressed in the context of
our audit of the financial report as a whole, and in forming our opinion thereon, but we do not provide
a separate opinion on these matters. For each matter below, our description of how our audit
addressed the matter is provided in that context.
We have fulfilled the responsibilities described in the Auditor’s Responsibilities for the Audit of the
Financial Report section of our report, including in relation to these matters. Accordingly, our audit
included the performance of procedures designed to respond to our assessment of the risks of
material misstatement of the financial report. The results of our audit procedures, including the
procedures performed to address the matters below, provide the basis for our audit opinion on the
accompanying financial report.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
118
1. Estimation of oil and gas reserves and resources
Why significant
How our audit addressed the key audit matter
Estimation of oil and gas reserves and resources
requires significant judgement and the use of
assumptions by the Group, as outlined in note 2
bb) (ii) of the Group’s financial report. These
estimates can have a material impact on the
financial statements, primarily in the following
areas:
capitalisation and classification of
expenditure as exploration and evaluation
(E&E) assets (Refer note 15) or oil and gas
assets (note 12);
valuation of assets and impairment testing
(note 13);
calculation of depreciation, depletion and
amortisation (DD&A) (note 4); and
•
•
•
•
estimation of the timing of decommissioning
and restoration activities (note 17).
•
Our audit procedures focused on the work of the
Group’s experts with respect to the hydrocarbon
reserve estimations.
Our procedures included the following:
•
•
•
assessed the qualifications, competence and
objectivity of the Groups’ internal experts
involved in the estimation process.
assessed controls over the estimation process
employed by the Group.
assessed whether key economic assumptions
used in the estimation of reserves and resources
volumes were consistent with those utilised by
the Group in the impairment testing of
exploration and evaluation and oil and gas
assets, where applicable.
analysed the reasons for reserve revisions, or
the absence of reserves revisions where
expected, and assessed movements in reserves
for consistency with other information that we
obtained throughout the audit.
•
ensured the reserves volumes used in the
determination of information recorded in the
financial statements, such as the calculation of
DD&A, valuation of assets and impairment
testing, and the calculation of decommissioning
provisions, were consistent with those addressed
through these procedures.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
119
2. Impairment assessment of oil and gas assets
Why significant
How our audit addressed the key audit matter
Australian Accounting Standards require the
Group to assess throughout the reporting
period whether there is any indication that an
asset may be impaired, or that reversal of a
previously recognised impairment may be
required. If any such indications exist, the
Group shall estimate the recoverable amount
of the asset. An asset is also required to be
tested for impairment immediately before an
exploration and evaluation asset is
transferred to assets in development.
As outlined in note 2 a) the Final Investment
Decision (FID) for the Sole Gas Project was
made on 29 August 2017. This triggered the
transfer of the project from exploration and
evaluation to Oil and Gas Assets - Asset in
Development. An impairment assessment was
performed immediately prior to the transfer
to Assets in Development. The Group’s
testing determined that no impairment was
required on transfer to Assets in
Development.
Impairment indicators were also present
during the period for certain cash generating
units (CGUs), and impairment testing was
undertaken where required. The Group’s
testing determined that no impairment of oil
and gas assets was required.
The impairment testing process is complex
and highly judgemental and is based on
assumptions and estimates that are affected
by expected future performance and market
conditions. Key assumptions, judgements and
estimates used in the formulation of the
Group’s impairment of and oil and gas assets
are set out in the financial report in note 2
bb).
We evaluated the assumptions and methodologies used
by the Group and the estimates made. In particular we
considered those estimates and judgements relating to
the forecast cash flows and the inputs used to formulate
those cash flows, such as discount rates, reserves and
resources, operating and capital costs, commodity prices
and foreign exchange rates.
We involved our valuation specialists to assist in these
procedures. Our audit procedures were undertaken
across all significant CGUs, with the extent of
procedures commensurate with the level of impairment
risk.
Specifically, we evaluated the discounted cash flow
models and other data supporting the Group’s
assessment for those CGUs where impairment indicators
were present. In doing so, we:
•
•
• understood future production profiles compared
to latest reserves and resources estimates, as
outlined in the key audit matter above, current
approved budgets and forecasts and historical
operations, where relevant;
evaluated commodity price assumptions with
reference to contractual arrangements, market
prices (where available), broker consensus,
analyst views, market regulators and historical
performance;
evaluated discount rates and foreign exchange
rates with reference to risk free rates, market
indices, market risk, company and project risk,
applicable tax rates, market expectations, and
historical performance;
compared future operating and capital
expenditure to current approved budgets,
forecasts, contractual arrangements and
historical expenditure, and ensured variations
were in accordance with our expectations based
upon other information obtained throughout the
audit;
tested the mathematical accuracy of the
Group’s discounted cash flow models.
•
•
We also considered the adequacy of the financial report
disclosures regarding key judgement and assumptions
with respect to the impairment assessment.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
120
3. Decommissioning and restoration provisions
Why significant
How our audit addressed the key audit matter
The Group has recognised decommissioning and
restoration provisions of $173.7 million at 30
June 2018 which are disclosed in note 17 of the
Group’s financial report. This includes the
assumption of additional decommissioning and
restoration liabilities from exited parties as set
out in note 2 a) and note 17.
The calculation of decommissioning and
restoration provisions requires judgement in
respect of asset lives, timing of restoration work
being undertaken, environmental legislative
requirements, the extent of restoration activities
required and future restoration costs.
Our audit procedures focused on the work of the
Group’s experts.
Our audit procedures included the following:
•
•
assessed the qualifications, competence and
objectivity of both the Group’s internal and
external experts involved in the estimation
process.
evaluated the adequacy of the expert’s work to
determine whether their work was appropriate,
including understanding the basis for forecast
cost assumptions for decommissioning and
restoration.
• assessed the effectiveness of relevant controls
over the Group’s decommissioning and
restoration provision estimation process.
• ensured the consistency in the application of
principles and assumptions to other financial
statement areas such as reserves estimation and
impairment testing.
•
•
tested the mathematical accuracy of the net
present value calculations.
assessed the Group’s disclosures in respect of
the decommissioning and restoration provisions.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
121
4. Accounting for deferred tax and Petroleum Resource Rent Tax
Why significant
How our audit addressed the key audit matter
We assessed the Group’s determination of tax
payable now and deferred tax. We involved our
taxation specialists to assist in this assessment. We
assessed the application of the methodologies used,
and the judgements involved in estimating the
utilisation of deferred tax benefits in the future, and
in assessing the offsetting of corporate income tax
deferred tax assets and liabilities.
We assessed the estimation of future taxable income,
the interpretation of PRRT and income tax legislation
and the consistency in the application of forecast
performance with other forecasts made, such as in
the Group’s impairment testing and corporate
modelling.
We assessed the Group’s disclosures in respect of
PRRT and income taxes which are included in the
summary of significant accounting policies in note 5
to the financial report.
The Group has recognised a net deferred tax
asset of $10.3 million at 30 June 2018 in
respect of corporate income tax which is
disclosed in note 5 to the financial report. In
arriving at the net deferred tax asset,
consideration has been given to temporary
differences arising on assets and liabilities, and
carry forward losses in respect of corporate
income tax, which are available for offset against
amounts payable in future periods.
The Group has interests in a number of assets
subject to the Australian Petroleum Resource
Rent Tax (“PRRT”) regime. The Group has
recognised a net deferred tax liability of $10.4
million at 30 June 2018 as disclosed in note 5.
Deferred tax assets in respect of the PRRT
regime, arising due to carried forward
undeducted expenditure, have not been
recognised in relation to a number of assets.
Further details are set out in note 5 to the
financial report.
The determination of the quantum, likelihood
and timing of the realisation of deferred tax
assets arising from corporate income taxes and
PRRT is complex and judgemental. The Group’s
accounting policies and disclosures regarding
PRRT and income taxes are included in the
summary of significant accounting policies in
note 2 bb) and in note 5 to the financial report.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
122
Information Other than the Financial Report and Auditor’s Report
The directors are responsible for the other information. The other information comprises the
information included in the Company’s 30 June 2018 Annual Report, but does not include the
financial report and our auditor’s report thereon. We obtained the Directors’ Report and the Overall
Financial Review that are to be included in the Annual Report, prior to the date of this auditor’s
report, and we expect to obtain the remaining sections of the Annual Report after the date of this
auditor’s report.
Our opinion on the financial report does not cover the other information and we do not and will not
express any form of assurance conclusion thereon, with the exception of the Remuneration Report
and our related assurance opinion.
In connection with our audit of the financial report, our responsibility is to read the other information
and, in doing so, consider whether the other information is materially inconsistent with the financial
report or our knowledge obtained in the audit or otherwise appears to be materially misstated.
If, based on the work we have performed on the other information obtained prior to the date of this
auditor’s report, we conclude that there is a material misstatement of this other information, we are
required to report that fact. We have nothing to report in this regard.
Directors’ Responsibilities for the Financial Report
The Directors of the Company are responsible for the preparation of the financial report that gives a
true and fair view in accordance with Australian Accounting Standards and the Corporations Act 2001
and for such internal control as the Directors determine is necessary to enable the preparation of the
financial report that gives a true and fair view and is free from material misstatement, whether due to
fraud or error.
In preparing the financial report, the Directors are responsible for assessing the Group’s ability to
continue as a going concern, disclosing, as applicable, matters related to going concern and using the
going concern basis of accounting unless the directors either intend to liquidate the Group or cease
operations, or have no realistic alternative but to do so.
Auditor’s Responsibilities for the Audit of the Financial Report
Our objectives are to obtain reasonable assurance about whether the financial report as a whole is
free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that
includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that
an audit conducted in accordance with Australian Auditing Standards will always detect a material
misstatement when it exists. Misstatements can arise from fraud or error and are considered material
if, individually or in the aggregate, they could reasonably be expected to influence the economic
decisions of users taken on the basis of this financial report.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
123
As part of an audit in accordance with Australian Auditing Standards, we exercise professional
judgement and maintain professional scepticism throughout the audit. We also:
•
Identify and assess the risks of material misstatement of the financial report, whether due to
fraud or error, design and perform audit procedures responsive to those risks, and obtain audit
evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not
detecting a material misstatement resulting from fraud is higher than for one resulting from error,
as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override
of internal control.
• Obtain an understanding of internal control relevant to the audit in order to design audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Group’s internal control.
• Evaluate the appropriateness of accounting policies used and the reasonableness of accounting
estimates and related disclosures made by the directors.
• Conclude on the appropriateness of the directors’ use of the going concern basis of accounting
and, based on the audit evidence obtained, whether a material uncertainty exists related to events
or conditions that may cast significant doubt on the Group’s ability to continue as a going concern.
If we conclude that a material uncertainty exists, we are required to draw attention in our
auditor’s report to the related disclosures in the financial report or, if such disclosures are
inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up
to the date of our auditor’s report. However, future events or conditions may cause the Group to
cease to continue as a going concern.
• Evaluate the overall presentation, structure and content of the financial report, including the
disclosures, and whether the consolidated financial statements represent the underlying
transactions and events in a manner that achieves fair presentation.
• Obtain sufficient appropriate audit evidence regarding the financial information of the entities or
business activities within the Group to express an opinion on the financial report. We are
responsible for the direction, supervision and performance of the Group audit. We remain solely
responsible for our audit opinion.
We communicate with the Directors regarding, among other matters, the planned scope and timing of
the audit and significant audit findings, including any significant deficiencies in internal control that
we identify during our audit.
We also provide the Directors with a statement that we have complied with relevant ethical
requirements regarding independence, and to communicate with them all relationships and other
matters that may reasonably be thought to bear on our independence, and where applicable, related
safeguards.
From the matters communicated to the Directors, we determine those matters that were of most
significance in the audit of the financial report of the current year and are therefore the key audit
matters. We describe these matters in our auditor’s report unless law or regulation precludes public
disclosure about the matter or when, in extremely rare circumstances, we determine that a matter
should not be communicated in our report because the adverse consequences of doing so would
reasonably be expected to outweigh the public interest benefits of such communication.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
124
Report on the Remuneration Report
Opinion on the Remuneration Report
We have audited the Remuneration Report included in pages 56 to 70 of the Directors’ Report for the
year ended 30 June 2018.
In our opinion, the Remuneration Report of Cooper Energy Limited for the year ended 30 June 2018,
complies with section 300A of the Corporations Act 2001.
Responsibilities
The Directors of the Company are responsible for the preparation and presentation of the
Remuneration Report in accordance with section 300A of the Corporations Act 2001. Our
responsibility is to express an opinion on the Remuneration Report, based on our audit conducted in
accordance with Australian Auditing Standards.
Ernst & Young
L A Carr
Partner
Adelaide
13 August 2018
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
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 Cooper Energy Limited for the financial year ended 30 June 2018,
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
13 August 2018
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 2018
Listing
The company’s shares are quoted on the Australian Securities Exchange under the code of “COE”.
Number of Shareholders
There were 7,114 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 2018)
Size of Shareholding
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
28
14
Number of holders
Number of Shares
% of issued capital
927
1,665
1,067
2,798
657
7,114
235,085
4,914,078
8,655,414
102,535,844
1,484,738,336
1,601,078,757
0.01
0.31
0.54
6.40
92.73
100.00
Total Performance Rights
17,846,179 Performance Rights
46,017,694 Share Appreciation Rights
Unmarketable Parcels
There were 974 members, representing 285,312 shares, holding less than a marketable parcel of 1,124 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.
HSBC Custody Nominees (Australia) Limited
JP Morgan Nominees Australia Limited
Citicorp Nominees Pty Limited
BNP Paribas Nominees Pty Ltd
National Nominees Limited
UBS Nominees Pty Ltd
BNP Paribas Noms Pty Ltd
Zero Nominees Pty Ltd
UBS Nominees Pty Ltd
Kavel Pty Ltd
HSBC Custody Nominees (Australia) Limited-GSCO ECA
Mirrabooka Investments Limited
Citicorp Nominees Pty Limited
Invia Custodian Pty Ltd
Nero Resource Fund Pty Ltd
Mr Leendert Hoeksema + Mrs Aaltje Hoeksema
Mr Timothy Bryce Kleemann
Levak Nominees Pty Ltd
Rocket Science Pty Ltd
Nero Resource Fund Pty Ltd
Units
% of Issued Capital
334,333,669
333,207,047
209,257,455
77,560,512
68,481,993
50,727,796
30,937,813
29,415,437
18,672,580
10,292,249
10,066,258
10,000,000
9,535,695
8,042,593
6,200,000
6,000,000
5,647,682
4,919,015
4,864,934
4,636,093
20.88
20.81
13.07
4.84
4.28
3.17
1.93
1.84
1.17
0.64
0.63
0.62
0.60
0.50
0.39
0.37
0.35
0.31
0.30
0.29
Totals: Top 20 holders of Ordinary Fully Paid Shares (Total)
1,232,798,821
77.00
Substantial Shareholder
The following were substantial holders in the company, as disclosed in substantial holding notices given to the Company as required by section
671B of the Corporations Act.
Name of entity
Challenger Ltd
JCP Investment Partners Ltd
CBA
FIL
AustralianSuper Pty Ltd
Number of securities in which substantial
shareholder has a relevant interest as at date of last notice
Voting power
as at date of last notice
142,008,750
103,752,292
102,621,837
99,461,842
88,849,874
8.87%
6.48%
6.41%
6.21%
6.02%
127
Shareholder Information
Enquiries and share registry
address
Shareholders with enquiries about their
shareholdings should contact the company’s
share registry, Computershare Investor
Services Pty Ltd, via the telephone contact
above.
Online shareholder information
Shareholders can obtain information
about their holdings or view their account
instructions online, as well as download
forms to update their holder details. For
identification and security purposes, you
will need to know your Holder Identification
Number (HIN/SRN), Surname/Company
Name and Post/Country Code to access. This
service is accessible via the Computershare
website.
Change of address
Shareholders who have changed their
address should advise Computershare in
writing. Written notification can be mailed or
faxed to Computershare at the address given
above and must include both old and new
addresses and the security holder reference
number (SRN) of the holding.
Change of address forms are available for
download from the Computershare website.
Alternatively, holders can amend their details
on-line via the Computershare website.
Shareholders who have broker sponsored
holdings should contact their broker to
update these details.
Annual Report mailing list
Shareholders who wish to vary their annual
report mailing arrangements should advise
Computershare in writing. Electronic versions
of the report are available to all via the
company’s website. Annual Reports will be
mailed to all shareholders who have elected
to be placed on the mailing list for this
document. Report election forms can be
downloaded from the Computershare website.
Forms for download
All forms relating to amendment of holding
details and holder instructions to the
company are available for download from
the Computershare.
Investor information
Information about the company is available
from a number of sources:
• Website: www.cooperenergy.com.au
• E-news: Shareholders can nominate to
receive company information electronically.
This service is hosted by Computershare
and can be accessed via Computershare’s
website
• Publications: the annual report is the
major printed source of company
information. Other publications include
half-yearly and quarterly reports, company
press releases, investor packs, and
presentations. All publications can be
obtained either through the company’s
website or by contacting the company
• Telephone or email enquiry:
to Don Murchland, Investor Relations
+61 439 300 932;
donm@cooperenergy.com.au
128
Corporate Directory
Directors
John C Conde AO, Chairman
David P Maxwell
Elizabeth A Donaghey
Hector M Gordon
Jeffrey W Schneider
Alice J M Williams
Company Secretary
Alison M Evans
Registered Office and Business Address
Level 8, 70 Franklin Street
Adelaide, South Australia 5000
Telephone: + 618 8100 4900
Facsimile: + 618 8100 4997
E-mail: customerservice@cooperenergy.com.au
Website: www.cooperenergy.com.au
Perth Office
Level 6, 160 St Georges Terrace
Perth, Western Australia 6000
Telephone: +61 8 6556 2101
Facsimile: +61 8 6556 2144
Auditors
Ernst & Young
121 King William Street
Adelaide, South Australia, 5000
Solicitors
Johnson Winter & Slattery
Level 9, 211 Victoria Square
Adelaide SA 5000
Bankers
Australia and New Zealand Banking
Group Limited
11-29 Waymouth Street
Adelaide, 5000
South Australia
NATIXIS
Hong Kong Branch
Level 72, International Commerce Centre
1 Austin Road West, Kowloon, Hong Kong
ABN AMRO Bank N.V., Singapore Branch
Level 26 One Raffles Quay South Tower
Singapore 048583
ING Bank N.V.
Level 31, 60 Margaret Street
Sydney NSW 2000
National Australia Bank Limited
Level 32, 500 Bourke Street
Melbourne VIC 3000
Share Registry
Computershare Investor Services Pty Limited
Level 5, 115 Grenfell Street
Adelaide SA 5000
Website: investorcentre.com/au
Telephone:
Australia 1300 655 248
International +61 3 9415 4887
Facsimile: +61 3 9473 2500
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