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Ovintiv2017 Annual Report
Cooper Energy Limited
ABN 93 096 170 295
Reporting Period,
Terms and Abbreviations
Annual Report
This document has been prepared to
provide shareholders with an overview
of Cooper Energy Limited’s performance
for the 2017 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 2017 Annual General Meeting of Cooper
Energy Limited ABN 93 096 170 295 (“the
company”) will be held at 10.30 am (ACDT)
on Thursday, 9 November 2017 in the
PwC Building, Level 11, 70 Franklin Street,
Adelaide, South Australia.
A formal 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
Reserves and resources
This Report uses terms and abbreviations
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 “2017”,
“FY17” or “2017 financial year” refer to
the 12 months ended 30 June 2017 unless
otherwise stated. References to “2016”,
“FY16” 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 & Design
FID: Final Investment Decision
FTE: Full Time Equivalent
GJ: gigajoules
HSEC: health, safety, environment and
community
km: kilometres
LNG: liquefied natural gas
LTI: lost time injury
m: metres
MMbbl: million barrels of oil
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.
MMboe: million barrels of oil equivalent
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.
NOPTA: National Offshore Petroleum Title
Administrator
PJ: petajoules
PRMS: Petroleum Resources Management
System
SCF: standard cubic feet
SPE: Society of Petroleum Engineers
TRCFR: Total recordable case
frequency rate
1C: Low estimate contingent resources
2C: Best estimate contingent resources
3C: High estimate contingent resources
1P: Proved reserves
2P: Proved & probable reserves
3P: Proved, probable & possible reserves
Front cover: Work on the Sole gas project commenced during the year. Cover shows horizontal directional drilling to establish the
subsurface shore crossing to link the Orbost Gas Plant with the pipeline to be laid from the Sole gas field in 2018.
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.
Darwin
Perth
Brisbane
Adelaide
Sydney
Melbourne
Hobart
Onshore Otway Basin
Offshore Otway Basin
Cooper Basin
Gippsland Basin
• Gas exploration acreage
• Casino Henry, Minerva
gas production projects
• Gas exploration acreage
• Western flank oil
production and exploration
• Sole gas project
• Manta gas resource
• Patricia-Baleen infrastructure
Key features:
Key figures:
• gas production, reserves and projects
For the year ended 30 June 2017
for supply to south-east Australia
• cash generating oil production from
the western flank of the Cooper Basin
• a 5 times growth trajectory in the
period to FY20 through projects in train
• a management team and board with
proven success in exploration, gas
commercialisation and building
resource companies
Production:
Gas: 4 PJ
Crude oil & condensate: 280,000 bbl
Net (debt)/cash:
$147.5 million
2P reserves:
11.7 million boe
Contingent resources:
77.6 million boe
Shares on issue:
1,140.3 million
1
The year in brief
Key themes
Building a portfolio style gas business to supply south-east Australia
• acquired gas production, plant, uncontracted gas and exploration
interests in the Otway Basin
• acquired interests that give 100% equity in the Sole gas field and
Orbost Gas Plant; and 100% interest in Patricia-Baleen
• first revenue as gas supplier
• contracted 104 PJ for future supply
• 2P gas reserves taken from zero to 56 PJ at 30 June, and 305 PJ after year-end
Sole gas project advancing to first gas in 2019
• agreement with APA Group for the sale and upgrade of Orbost Gas Plant and
processing of Sole and Manta gas
• Sole gas project approved as ready to proceed
• project funding and FID announced after year end
Building a leading mid-tier oil and gas company
• 2P reserves increased by 290% to 11.7 MMboe at 30 June
• appointment as Operator of offshore Otway Basin and Gippsland Basin licences
• team, management and systems upgraded consistent with new responsibilities
• admission to S&P/ASX 300 post-year-end
11.7
0.96
0.59
0.49
0.48
0.46
2.16
2.01
3.08
3.00
2013
2014
2015
2016
2017
2013
2014
2015
2016
2017
Proved & probable reserves
million boe at 30 June
2
Production
million boe, 12 months to 30 June
Key results
Financial
• revenue of $39.1 million, up from $27.4 million
• significant non-operating items of $(3.6) million after tax
• statutory net loss after tax of $12.3 million compared with
FY16 loss after tax of $34.8 million
• underlying net loss after tax of $8.7 million, down from FY16
underlying loss of $2.8 million
• cash flow from operating activities of $4.1 million, down
from $7.9 million
• cash and investments of $148.2 million, up from $50.8 million
at 30 June 2016
Operations: production, reserves, resources and exploration
• 1 recordable incident, zero lost time injuries
• Total Recordable Case Frequency Rate of 1.98 per million hours
• production of 0.96 million boe, up from 0.46 million boe
• 9 wells drilled; 7 successful
Safety: lost time injuries
and recordable cases
rate per million hours worked
4.50
4.00
3.50
3.00
2.50
2.00
1.50
1.00
0.50
0.00
1.98
0.00
2013 2014 2015 2016 2017
TRCFR
LTI
Proved & Probable Reserves
MMboe as at 30 June 2017
• proved and probable reserves of 11.7 million boe, up from
1.8
3.0 million boe
• contingent resources (2C) of 78 million boe, up from
9.9
64 million boe
Gas
Oil & condensate
433
166
123
81
94
0.51
0.38
0.38
0.25
0.22
2013
2014
2015
2016
2017
2013
2014
2015
2016
2017
Market capitalisation
$ million as at 30 June
Share price
cents per share at 30 June
3
Chairman’s Report
John Conde AO
Shareholders, whose support
for capital raisings enabled this
transformation, have benefited with
a total shareholder return over the
12 months to 30 June of 72.7%.
It is important that the key factors
underlying what appears a ‘break-
out’ year are noted so that the
strength of the company’s year-end
position is appreciated. I highlight
the main points.
1) The progress made in FY17
was the product of a visionary
gas strategy executed patiently
over the preceding 5 years,
as long term shareholders would
be aware. The growth achieved
during the year was possible
because (a) Cooper Energy
identified and responded quickly
to value accretive opportunities
consistent with its strategy and (b)
had equity market support for its
strategy and management team.
2) While the company’s business has
changed significantly, the values
which underpin its strategy have
not changed. An ongoing, over-
arching focus on care and total
shareholder return is considered
essential to delivering ongoing
returns for shareholders and
capturing the full potential of the
company’s position.
3) Throughout this period, the
company has retained a stable
board and senior management,
all of whom recognised, and were
committed to, the company’s
strategy. The company has also
promptly anticipated additional
requirements brought by its
success and opportunities and
has strengthened further the
company’s senior management
team, and recruited operational
staff and contractors. The
company is resourced
appropriately to manage current
and future opportunities.
I am pleased that Mr Hector Gordon
accepted a board position as non-
executive director after retiring from
his executive involvement. He was
previously an executive director.
Hector’s guidance and oversight of
the company’s technical matters has
been invaluable and I am delighted
that shareholders will continue to
have the benefit of his knowledge and
counsel as a member of the board.
The financial results for the year are,
to a large degree, reflective of the
costs of acquiring and integrating
gas assets with the supporting
systems and approvals. A statutory
loss of $12.3 million was recorded for
the 12 months to 30 June 2017. This
compares with the 2016 statutory loss
of $34.8 million.
The board’s decision in March to
approve the Sole gas project
as ‘ready to proceed’ was most
significant.
The completion of an over-
subscribed capital raising in
April raised $151 million in equity
funding for the project, enabling
work to proceed in advance of the
finalisation of debt funding. The
project is proceeding according to
schedule and budget.
The company’s balance sheet and
reserve position changed
significantly post-balance-date
with the announcement of the debt
and equity finance package that
will complete funding for the Sole
project and provide additional
capital for other opportunities and
commitments within the company’s
portfolio. The financing solution in
place for the project is considered
prudent given the cashflow
anticipated from Sole, the company’s
capital management forecasts and
the maintenance of a conservative
gearing position.
Fellow shareholders,
I am pleased to present
your company’s annual
report for the 2017
financial year.
The year was successful
and transformational.
The transactions, associated capital
raisings and project developments
have brought substantial change
and growth. Cooper Energy today
is enhanced dramatically from the
enterprise it was at 1 July 2016.
The company now generates the
majority of its revenue from the
production and supply of gas.
Our acreage and asset portfolio
is weighted towards offshore
Victoria. Market capitalisation has
increased from $94 million at 1 July
2016 to over $400 million at 30 June
2017. Our principal business has
expanded from minority onshore
oil production interests to being the
Operator and major, and in some
cases sole, interest holder of offshore
gas exploration, development and
production.
4
In closing, I acknowledge and
thank our Managing Director,
David Maxwell, his expanded
executive team, and indeed all of
our employees, for their unstinting
work in making the exceptional
progress reported in this Annual
Report. I thank also our share-
holders and other stakeholders
for their confidence and support,
I acknowledge and thank our
advisors, bankers, brokers and
underwriters, and I thank our
auditors – all for their thoroughness
and diligence and for their integrity
which we value greatly.
Finally, I thank my colleagues on
the board and our Company
Secretary for their counsel and
support during a year which has
required many extraordinary
meetings and discussions.
John Conde AO
Chairman
The finalisation of funding for Sole
enabled the declaration of the Final
Investment Decision for the Sole
project and the reclassification of the
field’s gas resource. Consequently,
proved and probable reserves as at
the date of this report are substantially
different from the figures at 30 June
2017 reported in this document.
Proved and probable reserves at
25 August were 54.1 million boe
compared to 11.7 million boe at
30 June 2017 and 3.0 million boe at
the beginning of FY17.
As the Managing Director outlines
in his report, Sole will deliver a
substantial increase in production
and revenue to Cooper Energy
when it commences production,
which is anticipated in the first half
of calendar 2019. From a broader
perspective, the project will deliver
a new source of gas supply to
south-east Australia at a time of
great market need.
Within Cooper Energy there
is a sense of pride in the role your
company has played in making
the Sole gas project a reality and
appreciation for the contributions
from our shareholders, customers,
financiers and project partners
including APA Group. This is an
achievement which is noteworthy:
Cooper Energy, which had a market
value of $94 million at the beginning
of the financial year, has, with the
support attracted from debt and
equity markets, and APA Group,
been able to bring a $605 million
gas project to Final Investment
Decision. Moreover, the company’s
capital management has enabled
this outcome to be achieved while
retaining 100% equity in Sole’s
gas reserves, thereby retaining
for Cooper Energy shareholders
the maximum exposure to value
increments from higher gas
prices and the passage of project
development.
5
Managing Director’s Report
David Maxwell
- production of gas in the offshore
- geographic; our sphere of
Otway Basin;
- the Sole gas project under
construction in the offshore
Gippsland Basin;
- a range of supply contracts with
blue-chip gas buyers;
- gas development opportunities and
prospective gas exploration acreage
in the Gippsland and Otway basins;
and
- low-cost oil production assets in the
western flank of the Cooper Basin.
With the core assets in place, the
focus of our gas strategy has shifted to
value creation through development,
production and marketing of our gas
and safe, efficient operations.
The details of the company’s assets,
financial and operating results for
the 2017 financial year are provided
in the sections titled Reserves and
Resources, Review of Operations,
Operating and Financial Review and
the financial statements included
in this Annual Report. I will review
the key features of Cooper Energy’s
performance and position, discuss
their significance, and finally address
our plans and expectations for your
company’s future.
Company transformation
The twelve months to 30 June 2017
was a transformational year in almost
every aspect of the company:
- business; the revenue, production
and reserves base shifted from 100%
reliance on oil to predominantly gas.
- scope of responsibilities; the
company has shifted from being
predominantly a non-operator
to being Operator in respect of the
most significant parts of its business,
encompassing operatorship
of offshore exploration, project
development and production
operations.
operations is now focussed entirely
on Australia. Cooper Energy ceased
operations outside the country with
divestment and withdrawal from the
previously remaining Indonesian
and Tunisian interests.
- production and reserves; annual
production rose by 105% and 2P
reserves by 290%.
- organisation; the number of
employees and contractors engaged
by the company at 30 June was
41 full time equivalent (FTE),
up from 25 at the start of the year.
On 1 July 2017, the corresponding
figure was 75 persons FTE. The new
employees include senior executives
with experience in offshore gas
development and operations who
have also joined the Management
Team. Contractors engaged
specifically on the Sole gas project
accounted for 30 FTE.
- capital structure and valuation; the
completion of two capital raisings
saw the company finish the year
with issued capital of 1,140.3 million
shares, compared with 435.2 million
at 30 June 2016. In this same period
the market capitalisation increased
360% from $94 million to $433 million.
The company now ranks among the
larger mid-tier Australian oil and
gas companies.
- Balance sheet and capital
management; the company’s
balance sheet is in the midst of
change as Cooper Energy proceeds
through development of the Sole
gas project. Cash on hand at
year-end rose from $49.8 million
to $147.5 million and debt finance
initiatives conducted during the
year culminated post-balance-date
with the signing of senior secured
reserve based lending facilities
with ANZ and Natixis, a leading
French bank. Further discussion of
the company’s capital management
follows on page 10.
In 2011, your company
identified a future
business opportunity
in the supply of gas to
south-east Australia
where it anticipated
a tightening market
following the onset of
LNG manufacture in
Queensland.
This forecast has been
proven accurate.
By the conclusion of the 2017 financial
year, Cooper Energy was favourably
positioned as a gas producer,
operator and developer of gas
projects and holder of a significant
volume of uncontracted gas available
for supply in the coming 13 years.
The improvement in the company’s
market capitalisation over the course
of the year and its subsequent
admission to the S&P/ASX300 index,
evidences market recognition of
Cooper Energy’s position and outlook.
Cooper Energy has completed the
establishment phase of its strategy;
the restructuring of the asset portfolio
to focus on Australia and creating
a cash-generating, portfolio-style
gas business. Our asset base now
comprises:
6
Victorian gas asset acquisition
A pivotal event in this transformation
was the acquisition of a portfolio of gas
assets in Victoria from Santos Limited.
The transaction, for initial cash
consideration of $62 million and
a further $20 million milestone
payment, involved the acquisition of
offshore acreage in the Otway and
Gippsland basins holding a net
61 petajoules of proved and probable
gas reserves and 143 PJ of contingent
2C gas resources effective from
1 January. Details of the assets
acquired and their contribution
to the year’s production is included
in the Review of Operations and
Operating and Financial Review from
pages 16 and 34 respectively.
Importantly, the transaction delivered
five key advances which accelerated
our gas strategy and which have
recast the company’s outlook:
1. Immediate access to the south-
east Australian gas market,
and increased revenue, from
cost-competitive Otway Basin
production. Cooper Energy’s
participation in the gas market has
been accelerated. The company
is now supplying gas to south-
east Australia and is marketing
uncontracted Otway Basin gas for
supply from March 2018. The cash
generated by the Otway Basin gas
assets has been instrumental in
securing funding for the company’s
Gippsland Basin gas projects.
2. 100% ownership of Gippsland
Basin gas assets. Moving to
100% equity in the Sole gas field
has substantially upgraded the
gas resources and future earnings
available to the company from
Sole and simplified the pathway
for development of the field and
the adjacent Manta gas field,
which is also wholly-owned by
Cooper Energy.
3. Upgrade to operational and
technical capabilities and
resources. Cooper Energy was
appointed Operator of the Casino
Henry, Sole and Patricia-Baleen
projects and the VIC/P44 licence.
A comprehensive process was
undertaken to ensure all saftey and
environmental management plans
were in place and to the satisfaction
of regulators and for the company
to demonstrate fitness to operate
offshore petroleum operations.
Cooper Energy is now among the
few independent Australian oil and
gas offshore production operating
companies, a feature which adds to
our value as a joint venture partner
and expands portfolio options.
The company’s talent pool of
operational professional staff
has been enlarged with the
Bottle manufacture by O-I, Australia’s largest glass container manufacturer and
the foundation customer for gas from the Sole gas field.
7
Managing Director’s Report
David Maxwell
recruitment of technical and
senior executive staff with proven
experience in offshore project
development and operation,
including in the assets acquired.
The acquisition of the offshore
Otway Basin assets has also
provided access to a comprehensive
suite of geological data, which has
been integrated onto the Cooper
Energy technical platform.
4. Addition of prospective gas
exploration acreage. The
company’s prospects and leads
inventory has been transformed
by the gas exploration potential of
the offshore Otway Basin acreage
acquired. The region is highly
prospective for gas, with exploration
having recorded good success
rates and resulted in a number
of field developments. Technical
review and analysis indicates the
presence of a number of gas
exploration targets, the development
economics of which are enhanced
by the proximity of pipeline and
processing infrastructure.
5. Upgraded production outlook.
The Otway Basin gas assets added
by the acquisition are expected
to drive three consecutive years
of production growth for Cooper
Energy, prior to a further step-up
in 2020 brought by the Sole
gas project.
Sole gas project
The decision by the company’s board
of directors in March 2017 to approve
the Sole gas project as ‘ready to
proceed’ was affirmed after year-end
with the announcement of a finance
package and the declaration of Final
Investment Decision. The project
will develop the Sole gas field to
supply approximately 24 petajoules
of gas per annum from 2019, thereby
bringing a new source of gas for
south-east Australia.
Commercial and technical work
completed during the year supported
the commercialisation of the field
8
through reducing technical and
construction risk and capital cost.
approximately 25 PJ of gas in its first
full year of production.
As a result, the project differs in a
number of respects from that outlined
in the previous year’s annual report.
The key features of the project include:
- a two-well development concept,
which provides reduced risk and
increases proved and probable
reserves by 7 PJ;
- separate but coordinated offshore
and onshore elements following
the signing of agreements which
include the sale of the Orbost Gas
Plant to APA Group Limited (APA).
Cooper Energy will undertake the
offshore development, including
shore crossing, and APA will
upgrade and operate the plant to
process gas from Sole under a pre-
determined tariff. The anticipated
cost of the offshore development to
be undertaken by Cooper Energy
is $355 million;
- 180 PJ of the field’s gas has been
contracted under long-term take-
or-pay contracts to a portfolio of
four gas buyers; AGL Energy,
EnergyAustralia, Alinta Energy and
O-I Australia. The balance is to be
retained for contracting at a later
date as value determines;
- fixed price contracting for the
majority (estimated to be 62%) of
Cooper Energy’s project costs; and
- a completion schedule which
provides for first gas into the
upgraded Sole plant in March 2019
and sales from mid-2019.
Work on Sole is proceeding in accord
with the project budget and schedule.
Further details on the Sole project are
contained in the Review of Operations
on page 18.
Manta gas project
Development of the Manta gas and
liquids resources adjacent to Sole has
been identified as a second-stage gas
development in the Gippsland Basin.
The project is forecast to produce
As discussed on page 19, the case for
Manta development was advanced
during the year by stronger demand
and price indications, agreement
with APA on processing access and
terms at the Orbost Gas Plant and the
substantial improvement to capital
cost knowledge obtained through the
Sole development project.
Current expectations are that the
development of Manta will be subject
to the results of the Manta-3 appraisal
and exploration well. Opportunities to
drill Manta-3 in 2019, leveraging the
local presence of the Ocean Monarch
rig mobilised to drill the Sole
production wells, are being evaluated.
Drilling of Manta-3 in this time frame
could lead to Manta commencing
production in FY22.
Care
Cooper Energy has two key
requirements of all its activities and
plans: that they deliver acceptable
returns and that they be performed
with due care for the people,
environments and communities who
may be affected. A report on the
sustainability related elements of our
operations is provided on page 24.
The company recorded a single
recordable safety and environment
incident in the since-divested
Indonesian operations. There were no
lost time incidents. A zero injury-zero
incident performance remains the
minimum acceptable safety standard
for your company.
The scope of the company’s care
obligations increased significantly
during the year with the acquisition
of the Otway and Gippsland basin
assets. The company’s appointment
as Operator of the Sole, Casino Henry
and Patricia-Baleen projects required
regulatory approval of the resources,
capabilities, safety and environmental
management systems for each
operation. I have noted the strategic
significance of this achievement above
and commend the efforts of those who
have contributed to this achievement.
Of course, documentation, systems
and accreditation do not constitute
performance. The transformation
of the company has brought an
accompanying expansion to our
accountability of care. We remain
mindful that acceptable performance
requires incident-free operations
in every hour of every day at
every location.
Cooper Basin
Our oil production interests in the
western flank of the Cooper Basin
remain a valuable element of
the company’s cash generation.
The performance of the PEL 92 Joint
Venture highlighted the quality of
this asset with low production costs,
good drilling results and evidence
of untapped potential.
Cash production costs, including
royalties and transportation of
A$29.77/bbl for the twelve months
to 30 June compare with the average
sale price received of A$61.89/bbl.
Production of 0.25 million barrels of
oil was lower than the previous year,
a result anticipated in view of the
suspension of drilling in the previous
year due to low oil prices and natural
field decline.
The resumption of drilling recorded
good results, with seven successful
wells from the nine wells drilled
during the year. Six of the successful
wells were drilled on the Callawonga
oil field, including a five-well
campaign to assess the production
potential of the McKinlay Member
Sandstone, which has hitherto been
lightly exploited. The connection of
these wells, scheduled for the first
half of FY18, will give confirmation of
long-term productive capacity.
It is noteworthy that Cooper Basin
field performance and drilling
resulted in upgrades of 0.8 MMbbl
to the company’s proved and
probable reserves, representing a
135% reserves replacement ratio in
the region. The year’s results have
reinforced the prospectivity of the
acreage held by the PEL 92 Joint
Venture, particularly for incremental
oil in existing producing fields.
Financial results
A detailed analysis and discussion
of the financial results for the year
is provided in the Operating and
Financial Review which commences
on page 34.
The financial results were affected
by the substantial changes in the
company’s portfolio and activities
during the year.
Callawonga facilities, Cooper Basin. The field was the location for six of the nine wells
drilled by the company during the year, all of which were successful.
9
Managing Director’s Report
David Maxwell
The exit from international operations
in Indonesia and Tunisia incurred
impairments and exit provisions
whilst the acquisition, integration
and financing of new Australian gas
assets brought additional costs.
The company recorded a reduced,
statutory loss after tax of $12.3 million
compared with the statutory loss of
$34.8 million in the previous year.
Revenue increased by 43% over the
previous year due to the six-month
contribution from the Otway Basin
gas assets, rising from $27.4 million
to $39.1 million despite the lower oil
volumes discussed above.
Reserves
The 290% increment to reserves
in the 2017 financial year was the
precursor to the larger increase
after year end brought by the Final
Investment Decision for Sole.
Proved and probable reserves of
11.7 million boe at 30 June 2017
compares with 3.0 million at the
beginning of the year, with the latter
figure including 1.7 million boe
attributable to the Indonesian assets
divested during the year.
The increase in year-end reserves is
largely attributable to the Victorian
gas asset acquisition, which
contributed proved and probable
reserves of 10.6 million boe. As
noted at the outset of this report, the
acquired assets brought change to
the composition and location of the
company’s reserves. Gas and gas
liquids located in the Otway Basin
accounted for 85% of proved and
probable reserves compared with
zero at the beginning of the year.
The company’s contingent resources
of 77.6 million boe at year-end was
13.3 million boe higher, notwith-
standing the removal of 11.7 million
boe attributable to divested Tunisian
and Indonesian assets. The increased
contingent resources highlight the
exposure of the company to gas
development opportunities in the
Gippsland and Otway basins.
10
The largest of these is the Sole gas
project and the Final Investment
Decision for the project on 29 August
resulted in an uplift of 43 million boe
to the proved and probable reserves
and a corresponding reduction to
contingent resources at 30 June.
2C contingent resources attributable
to the Manta (21 million boe) and
Black Watch fields (2 million boe)
offer further reserves additions in
the longer term.
South-east Australian gas
market
Prior to FY17, Cooper Energy’s
earnings were essentially driven by
three factors: crude oil prices,
operating costs and its crude oil
production. In FY17, gas accounted
for the majority of the company’s
revenue and its share is expected to
continue to increase. Moreover,
approximately 95% of the company’s
capital expenditure budget for FY18
is allocated to gas projects.
The company applies a portfolio
approach to the marketing of its
gas, mixing long-term take or pay
contracts that offer assured cash
flows as required with a range of
shorter term contracts for exposure
to higher value where appropriate.
Tightening gas supply in eastern
Australia over the past twelve months
has been reflected in rising and
volatile gas spot prices, which
have attracted unprecedented
attention, and the introduction of
supply safeguard provisions by the
federal government in the form of
the Australian Domestic Gas Supply
Mechanism.
Given the recent change to the
company’s business base and the
publicity concerning prices, it is
appropriate that I briefly discuss
the company’s exposure and
strategy in relation to gas prices and
the implications of the Australian
Domestic Gas Supply Mechanism.
In respect of price exposure, the
company’s gas assets are highly
cost competitive in its chosen south-
east Australian market.
The Casino Henry and Minerva gas
operations are considered to be
among the lowest cost options of
current supply sources for gas
delivered to Melbourne city-gate.
Independent analysis has found the
Sole gas project to possess lower
delivered cost to Melbourne than
other new potential sources of supply.
Approximately 75% of Sole’s gas
reserves are already contracted at
stable prices.
Moreover, the projects are economic
in lower gas price environments than
is currently prevailing or expected.
Casino Henry, Sole and Manta are
considered economic at prices
well below those prevailing in FY17
and those modelled to result from
influx of gas such as could occur
through the Australian Domestic Gas
Supply Mechanism.
In summary, it is assessed that supply
from the company’s operations
is unlikely to be displaced by higher
cost gas resulting from operation of
the Australian Domestic Gas Supply
Mechanism and that such action does
not threaten the anticipated returns
from the company’s gas business.
Balance sheet and capital
management
The company generated $4.1 million
net cash flow from operating
activities for the financial year, a
figure which incorporates 6 months’
contribution from the Otway gas
assets, expenditure associated with
their acquisition and integration and
a $3.7 million payment to complete
withdrawal from Tunisian acreage.
The gas projects provide the
opportunity for substantial additions
to shareholder value. Consistent
with our strategy and objectives, the
development of these projects and
the attendant capital management will
be driven by total shareholder return.
The Sole project is illustrative of
this approach where, through the
Orbost Gas Plant sale and processing
agreement struck with APA Group
during the year, the company
has been able to concentrate its
capital and risk exposure to its core
competency, upstream development.
In doing so, the project cost for
Cooper Energy has been reduced
from $605 million to $355 million.
The balance sheet, and accompanying
note on events after the reporting
period published in this report,
show the implementation of capital
management initiatives to fund the
company’s growth. As the balance
sheet reports, the company’s
cash positon at 30 June rose from
$49.8 million to $147.5 million, an
increase attributable to the equity
raising completed in April to raise
funds for the Sole gas project.
Debt funding for the project, still in
progress at year-end, was announced
on 29 August with a $250 senior
secured reserve based lending facility
fully underwritten by banks ANZ and
Natixis, supported by a $15 million
working capital facility. The debt
package has been accompanied by a
$135 million, 2 for 5 entitlement issue.
The finance package adopted
was selected after analysis and
consideration of bank and non-bank
debt finance options. Ultimately the
combination of bank debt and equity
finance adopted was selected as
the most accretive for shareholder
returns, funding Sole plus other value
adding activities within the portfolio,
at highly competitive interest rates
whilst retaining a prudently geared
balance sheet.
The company’s portfolio offers a
number of additional opportunities
for value creation available in the
period prior to Sole commencing
production. The advancement
and funding of these opportunities
will be undertaken with the same
focus on total shareholder return that
has driven our portfolio development
over the past 5 years.
Outlook
In my concluding comments to the
previous annual report I noted that
2017 was expected to be the year
when the various strategic elements
pursued in the preceding four years
converged and Cooper Energy
emerged with a distinctly different
form and outlook. As this report
documents, this is what occurred,
albeit the company has emerged
larger and with greater opportunity
than envisaged at that time.
The decisions made mean FY17 was
the first year of a multi-year growth
trajectory on offer from the existing
asset base, before consideration of
any contribution from exploration
success or inorganic growth.
The portfolio and capital expenditure
plans have the capacity to deliver
successive increases in production
over the coming 3 years such that,
based on existing asset equities,
annual output could rise from 1 million
boe in FY17 to over 6 million. The key
drivers are expected to be:
• in FY18 – the first full year of
production from the Otway Basin
gas assets, the conduct of well
workover on the Casino field and, in
the Cooper Basin, the connection of
the wells drilled on the Callawonga
oil field in FY17;
• in FY19 – the benefits of the Casino
well workover, the prospect of an
uplift in Otway Basin gas production
from development drilling on
the Henry gas field and the
commencement of production from
Sole in FY19; and
• in FY20 – the first full year of
production from Sole.
The drilling and development of the
Manta field in the Gippsland Basin
holds the potential for further growth
in later years.
Much of the work to translate this
potential into value for shareholders
is expected to be undertaken in the
12 months from 1 July 2017 to 30 June
2018, including:
• progression of the Sole gas project
including to approximately 50%
complete;
• the negotiation of new sales and
processing contracts for Otway
Basin gas from 1 March 2018;
• development and other activities
on the Casino Henry field including
well workover and preparation
for, and subject to rig schedules
and joint venture agreement, the
commencement of, a development
well on the Henry field; and
• evaluation of gas exploration
opportunities in the onshore and
offshore Otway Basin.
In the Cooper Basin, ongoing
activities to optimise production and
address prospectivity for addition
of reserves close to infrastructure
are anticipated.
The development of your company
in FY17 has, through a mixture of
strategic planning, execution, as well
as good fortune, coincided with the
most promising business climate
for the upstream gas business since
its origins. Cooper Energy is now
well positioned with gas development
capabilities, projects and operator
credentials to pursue and develop
these opportunities for the benefit of
our shareholders.
FY17 has been a year of great
development and progress for
Cooper Energy. Thank-you to our
team of staff and contractors that have
made this possible.
I look forward to reporting on our
progress.
David Maxwell
Managing Director
11
Reserves and resources
Reserves
Cooper Energy’s proved and probable reserves at 30 June 2017 are assessed to be 11.7 million barrels of oil
equivalent (MMboe). This is an increase of 8.7 MMboe from 30 June 2016. The key factors contributing to the material
revisions are:
• completion of the acquisition of Santos Limited’s offshore Victorian gas assets, effective 1 January 2017;
• increase in Cooper Basin (PEL 92) oil reserves following new drilling at the Callawonga field and identification of
additional development opportunities at the Butlers and Parsons fields;
• divestment of the Indonesian production assets to Bass Oil Limited, effective 1 October 2016; and
• production of 1.0 MMboe.
Reserves at 30 June 2017 (MMboe)
Category
Basin
Developed
Undeveloped
Total 1,2
Proved
(1P)
Proved & probable
(2P)
Proved, probable &
possible (3P)
Cooper
Otway
Total
Cooper
Otway
Total
Cooper
Otway
0.6
0.3
0.9
1.1
5.9
7.0
1.7
6.2
7.9
1.1
0.6
1.8
2.4
7.5
9.9
3.6
8.1
11.7
2.0
0.9
2.9
5.1
10.7
15.8
Total
7.0
11.7
18.7
1. The reserves exclude Cooper Energy’s share of future crude fuel usage.
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
Reserves at 30 June 2016
FY17 Production
Revisions
Reserves at 30 June 20171,2
Proved
(1P)
1.6
(1.0)
7.3
7.9
Proved & probable
(2P)
Proved, probable &
possible (3P)
3.0
(1.0)
9.7
11.7
4.8
(1.0)
14.9
18.7
1. The reserves exclude Cooper Energy’s share of future crude fuel usage.
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.
Contingent resources
Cooper Energy’s Australian 2C (P50) contingent resources at 30 June 2017 have increased since 30 June 2016 by
13.3 MMboe to a total of 77.6 MMboe. The key factors contributing to the material revisions are:
• completion of the acquisition of Santos Limited’s offshore Victorian assets, effective 1 January 2017;
• exit of Beach Energy Limited from the BMG joint venture effective 26 October 2016, taking Cooper Energy’s equity in
the Basker and Manta fields in VIC/RL13, VIC/RL14 and VIC/RL15, offshore Gippsland Basin to 100%;
• divestment of the Indonesian production assets to Bass Oil Limited, effective 1 October 2016; and
• completion of withdrawal from Tunisia.
12
Contingent resources at 30 June 2017 (MMboe)
Category
Basin
Gippsland
Otway
Cooper
Total 1
Gas
PJ 1
291
12
0
304
1C
Oil
MMbbl
4.0
0.0
0.1
4.1
Total 1
MMboe
54.1
2.1
0.1
56.3
Gas
PJ 2
388
19
0
407
2C
Oil
MMbbl
7.6
0.0
0.1
7.7
Total 1
MMboe
74.3
3.2
0.1
77.6
Gas
PJ 2
532
27
0
559
3C
Oil
MMbbl
12.1
0.0
0.2
12.3
Total1
MMboe
103.6
4.7
0.2
108.5
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.
2. The conversion factor of 1 PJ = 0.172 MMboe has been used to convert from Sales Gas (PJ) to Oil Equivalent (MMboe).
Movement in contingent resources (MMboe)
Category
Contingent resources at 30 June 20161
Revisions
Contingent resources at 30 June 20172
1C
39.7
16.6
56.3
2C
64.3
13.3
77.6
3C
112.4
(3.9)
108.5
1. Resources at 30 June 2016 as reported in the Cooper Energy 2016 Annual Report to the ASX on 11 October 2016.
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.
Notes on calculation of reserves and resources
Cooper Energy has completed its own estimation of reserves and resources based on information provided by the permit Operators
Beach Energy Limited, Senex Limited, Santos Limited, and BHP Billiton Petroleum (Victoria) Pty Ltd in accordance with the definitions
and guidelines in the Society of Petroleum Engineers (SPE) 2007 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.
Reserves
Under the SPE PRMS, reserves are those petroleum volumes that are 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.
Contingent resources
Under the SPE PRMS, contingent resources are those petroleum volumes that are estimated, as of a given date, to be potentially
recoverable from known accumulations but for which the applied projects are not considered mature enough for commercial development
due to one or more contingencies.
The contingent resources assessment includes resources in the Gippsland, Otway and Cooper basins. The following contingent resources
assessments have been released to the ASX:
• Sole on 27 February 2017;
• Manta on 16 July 2015; and
• Basker and Manta on 18 August 2014.
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 estimates provided in the releases continue to apply.
Qualified petroleum reserves and resources evaluator statement
The information contained in this report regarding the Cooper Energy reserves, contingent resources and prospective resources report
is based on, and fairly represents, information and supporting documentation reviewed by Mr Andrew Thomas who is a full-time employee
of Cooper Energy Limited holding the position of General Manager – Exploration & Subsurface, holds a Bachelor of Science (Hons),
is a member of the American Association of Petroleum Geologists and the Society of Petroleum Engineers, is qualified in accordance with
ASX listing rule 5.41, and has consented to the inclusion of this information in the form and context in which it appears.
13
Review of Operations
Cooper Energy’s operations primarily comprise:
• gas production in the Otway Basin, offshore Victoria
• oil production in the Cooper Basin, onshore South Australia
• development of the Sole gas field in the Gippsland Basin, offshore Victoria; and
• exploration for oil and gas in the Cooper, Otway and Gippsland basins.
Production
Cooper Energy’s oil and gas production for the year totaled 0.96 MMboe
compared with 0.46 MMboe in the previous year. The increase in production is
due to output from the Otway Basin gas operations, which were acquired effective
from 1 January 2017 and contributed 71% of the company’s production for the year.
The contribution from the Otway Basin more than offset lower output from natural
decline in the Cooper Basin in the absence of drilling in the previous year and
through the divestment of Indonesian operations effective from 1 October 2016.
Production MMboe
Otway Basin, Australia
Cooper Basin, Australia
South Sumatra, Indonesia
Total
2016
-
0.32
0.14
0.46
2017
0.68
0.25
0.03
0.96
Production by region
MMboe
1.2
1.0
0.8
0.6
0.4
0.2
0.0
0.03
0.25
0.68
0.14
0.32
2016
2017
Otway Basin, Australia
Cooper Basin, Australia
South Sumatra, Indonesia
14
Drilling
Drilling was concentrated entirely on the Cooper Basin where Cooper Energy participated in 9 wells
during the year, 7 of which were successful. All of the successful wells, with the exception of Worrior-11,
were drilled on the Callawonga oil field, the largest in the company’s Cooper Basin acreage.
The 9 well program comprised the drilling of four oil development wells (Callawonga-12, -15 and -16,
and Worrior-11), three oil appraisal/development wells (Callawonga-14, -17 and -18), one appraisal
well (Butlers-9), and one exploration well (Penneshaw-1) in the Cooper Basin during the year.
The Callawonga drilling campaign successfully targeted previously undeveloped reserves in the
McKinlay Member sandstone. Oil production from these wells is expected to begin later in 2017.
Type
Exploration
Appraisal
Area
Tenement
Well
Cooper Basin
PRL 87
Penneshaw-1
Cooper Basin
Butlers-9
Result
P&A
P&A
Appraisal/Development
Cooper Basin
Appraisal/Development
Cooper Basin
Appraisal/Development
Cooper Basin
Development
Development
Development
Development
Cooper Basin
Cooper Basin
Cooper Basin
Cooper Basin
* Cased and suspended as a future oil production well.
PPL 245
PPL 220
PPL 220
PPL 220
PPL 220
PPL 220
PPL 220
PPL 207
Callawonga-14
Oil well*
Callawonga-17
Oil well*
Callawonga-18
Oil well*
Callawonga-12
Oil producer
Callawonga-15
Oil well*
Callawonga-16
Oil well*
Worrior-11
Oil producer
Site works for installation of the shore crossing, Orbost Gas Plant, showing horizontal directional drillers
at right and elevated conduits for guiding umbilical casing and gas pipe into the shore crossing.
15
Review of Operations
Otway Basin - Offshore
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 59AR17
In the Otway Basin offshore Victoria
Cooper Energy holds interests in 2
producing gas projects; one onshore
gas plant, 2 retention leases and an
exploration licence.
The offshore Otway Basin portfolio
comprises:
- a 50% interest and Operatorship
of the producing Casino Henry gas
project (VIC/L24 and VIC/L30);
- a 50% interest and Operatorship
of the retention licences VIC/RL11
and VIC/RL12;
- a 50% interest and Operatorship of
the VIC/P44 exploration licence; and,
- a 10% interest in the Minerva gas
project comprising the offshore
licence VIC L/22 and the Minerva
Gas Plant onshore.
These interests were acquired
effective from 1 January 2017.
Operator responsibilities were
assumed subsequent to year-end.
16
The Casino Henry Joint Venture has
submitted applications to NOPTA,
to renew VIC/RL11, VIC/RL12 and to
vary the work program of VIC/P44.
Casino Henry gas project
The Casino Henry gas project
produces 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 to 25 kilometres
offshore Victoria in water depth
ranging from 65 to 71 metres.
The licenses are covered entirely
by high-quality 3D seismic surveys
acquired in the years 2001 to
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.
The project 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
the fields is transported via 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.
Successful optimisation trials were
conducted during the year to reduce
the onshore plant inlet pressure for
purpose of enhancing flow rates
and recoverable reserves. Additional
optimisation work will be undertaken
in 2017 to pursue further gains.
Commercial negotiations are in
progress to extend the arrangements
to process gas through the Iona facility
beyond February 2018.
Cooper Energy’s share of production
from Casino Henry during the year
was 3.28 PJ of gas and 1,960 barrels
of condensate.
Cooper Energy’s share of proved
and probable gas reserves at Casino
Henry at 30 June 2017 is assessed
to be approximately 56 PJ, of which
13 PJ is developed. The company
is preparing development options for
the production of the undeveloped gas
for joint venture consideration in FY18.
Minerva gas project
The Minerva gas field is located
in production licence VIC/L22
approximately 9 kilometres 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 kilometre
trunkline. Cooper Energy holds a
10% interest in these assets.
Production from Minerva commenced
in mid-January 2005. The field has
produced beyond expectations and
is believed to be approaching end of
life and is anticipated that production
will cease during FY18.
Minerva contributed 0.75 PJ and
1,696 barrels of condensate to
the company’s production in FY17.
Undeveloped fields and
exploration
In VIC/RL11 and VIC/RL12, the
development prospects for the Black
Watch gas field will be the subject of
further review. In the adjacent licence
VIC/L1(V), Origin Energy Limited
has successfully developed offshore
gas at Halladale and Speculant by
drilling extended reach wells from
shore and potential exists for a
similar development at Black Watch.
Significant exploration potential
is recognised in the offshore Otway
acreage. Thirty-three exploration
prospects have been identified and
the majority are the same play type
as the current producing gas fields.
The majority of the prospects are
located less than 10 kilometres from
tie-in points to the existing offshore
production pipeline, offering future
exploration success simple and close
access to production infrastructure.
The work program for VIC/P44
includes seismic inversion studies to
be conducted in FY18. The studies
will enhance assessment of the
presence of gas in the prospects
which may result in definition of
potential future drilling candidates.
Minerva Gas Plant, Otway Basin
17
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. Cooper Energy increased its
stake from 50% to 100% effective
from 1 January 2017. VIC/L32 is a
production licence awarded during
the year which replaces the retention
licence VIC/RL3.
- 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
acquired effective from 1 January;
and
- a 100% interest in the onshore
Orbost Gas Plant. As noted earlier
in this report, this interest is to be
acquired by APA Group on the
completion of conditions precedent
under an agreement announced
1 June 2017. Under the agreement,
APA Group will acquire, upgrade
and operate the plant to process
gas from Sole, Manta and potentially
other fields.
Sole gas project
Development of the Sole gas field
commenced during the year and is
on schedule for the start of gas
production from the field to
the upgraded Orbost Gas Plant in
May 2019.
The development comprises separate
onshore and offshore workstreams,
with the former to be undertaken by
APA Group pursuant to the acquisition
agreement announced 1 June 2017.
The offshore element, to be conducted
by Cooper Energy, comprises two
near-horizontal development wells,
subsea completion, fabrication and
installation of subsea well-heads,
pipeline and umbilical connections
and the construction of a shore
crossing to connect to the plant.
18
VICTORIA
Orbost
EAST E R N G
Sydney
E LIN E
S P I P
A
M e l b o u r n e
Orbost Gas Plant (APA*)
Lakes Entrance
Patricia-Baleen
VIC/L21 (100%)
Longtom
Tuna
Kipper
VIC/L32 (100%)
Sole
Snapper
Marlin
Flounder
Chimaera
Manta
Basker
Gummy
VIC/RL15 (100%)
Fortescue
Kingfish
VIC/RL14 (100%)
VIC/RL13 (100%)
*APA to acquire, upgrade and
operate Orbost Gas Plant under
agreement announced 1 June 2017
Cooper Energy tenement
Gas field
Oil field
Gas pipeline
Oil pipeline
0
20
kilometres
Gippsland_68AR17
Plan area
TAS
Sole pipeline; indicative
Pipeline options
The offshore project has an estimated
capital cost of $355 million;
approximately 60% of which is to be
performed under fixed price contracts.
Site works commenced in the final
quarter of FY17. The Final Investment
Decision (FID) was declared
subsequent to year-end with the
announcement of fully underwritten
debt and equity financing. With
FID achieved, it is expected that the
agreement with APA Group will
complete with the finalisation of
financing documentation in the first
half of FY18.
The Sole gas field was assessed to
hold a 2C contingent resource of
249 PJ of gas as at 30 June. This was
reclassified as proved and probable
reserves of 249 PJ following Final
Investment Decision for the project
subsequent to year-end. Gas supply
from the field is forecast to be
approximately 24 PJ per annum.
Marketing activity secured contract
coverage sufficient for financing, such
that 20 PJ per annum is subject to
binding long term sales agreements
with AGL Energy, EnergyAustralia,
Alinta Energy and O-I Australia.
It is expected that Sole gas currently
uncommitted will be contracted under
shorter term agreements as value
recommends. Further discussion of
the company’s gas marketing efforts,
strategy and position is provided
in the Managing Director’s Report on
pages 8 and 10.
Manta gas project
The Manta gas field is located in
retention licences VIC/RL13, VIC/RL14
and VIC/RL15, 35 kilometres from Sole
and 58 kilometres from the Orbost
Gas Plant. The field is assessed to
contain contingent resources of 106 PJ
of gas and 3.2 MMboe of condensate.
Prospective resources are present at
Manta, with a best estimate unrisked
prospective resources estimate
of 105 MMboe comprising 526 PJ
of gas, 12.9 MMbbl of condensate
and 1.5 MMbbl of oil. The estimated
quantities of petroleum that may
be potentially recovered by the
application of future development
projects 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’s proximity to Sole and
Orbost 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 drilling, control umbilicals,
plant, redundancies and maintenance.
Patricia-Baleen
Patricia-Baleen is a largely depleted
gas field located in VIC/L21. The
field and associated pipeline is in a
suspended state and under care
and maintenance after being shut-in
in 2008.
Sole gas project; welded pipe laid out ready
for installation in shore crossing at Orbost.
19
Review of Operations
Cooper Basin
139°20'
139°40'
39 40
-27°40'
100 101
99
96
Rincon
North
98
Rincon
k
e
e
r
C
r
e
p
o
o
C
Cooper Energy tenement
Other tenements
Oil field
Gas field
Oil pipeline
Gas pipeline
95
94
93
Callawonga
98
97
99
100
PRLs 85 to 104 (25%) (ex ‘PEL 92’)
97
93
91
92
90
87
89
Parsons
Windmill
Sellicks
86
Christies
Silver Sands
102
Elliston
85
87
86
-28°
Perlubie
Perlubie South
Butlers
85
Germein
101
92
104
103
Lycium Hub
91
88
90
Plan area
TAS
oper 78AR17
Cooper_78AR17
Cooper Energy holds interests
in three exploration licenses,
28 retention licences and 11
production licences in the South
Australian Cooper Basin. The
company’s activities are primarily
focussed on tenements held by the
PEL 92 Joint Venture1 (‘PEL 92’) on
the western flank of the basin, which
provided approximately 26% of
Cooper Energy’s total production in
FY17. The Worrior Field (PPL 207)
supplied 2% of Cooper Energy’s total
production for the year.
20
0
20
kilometres
PEL 93 (30%)
Joint venture and tenement interests
comprise:
- a 25% interest in the PEL 92 Joint
Venture which holds PRL’s 85 to
104 and includes the oil producing
Butlers, Callawonga, Christies,
Elliston, Germain. Parsons, Perlubie,
Rincon, Rincon North, Sellicks, Silver
Sands, and Windmill 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).
139°30'
139°40'
139°50'
PPL 207 (30%)
Worrior
1 kilometre
Inset
PEL 93 (30%)
Plan area
TAS
Cooper Energy tenement
Other tenements
Oil field
Gas field
Gas pipeline
Oil well
Oil show
The Cooper Basin operations became
the company’s sole source of oil
production after the divestment of
Indonesian operations in September.
The company’s share of oil
production from the Cooper Basin
during the year was 0.25 MMbbl,
94% of which was from the PEL 92
Joint Venture. Production for the
12 months to 30 June was 22% lower
than the previous year, an outcome
which reflects the impact of the
suspension of drilling operations
from May 2015 to August 2016 and
natural field decline.
Additional potential at the
Callawonga oil field was identified
in the McKinlay Member Sandstone
which lies immediately above the
main producing reservoir, the
Namur Sandstone. Callawonga-12
drilled at the beginning of the year
was successfully completed as a
Worrior
See inset
PPL 207
PEL 93 (30%)
-28°20'
O P E R B A SIN
C O
-28°30'
0
10
kilometres
-28°40'
Cooper_77_AR17
McKinlay Sandstone oil producer
and highlighted the potential of the
previously undeveloped oil reservoir.
A further five appraisal and
development locations (Callawonga
12-18) were drilled to delineate
additional McKinlay potential and to
appraise the extent of the field. All
wells were successful and production
from these wells is scheduled to
commence in the December quarter
of 2017. The drilling campaign
resulted in a net increase to 2P field
reserves of 0.5 MMbbls. There is
potential to conduct another drilling
campaign in the 2018 calendar year
pending the outcome of production
performance. The potential of other
fields to provide similar results
from the previously under-exploited
McKinlay Member is under review.
A project to upgrade the Callawonga
oil production facilities and increase
the total fluids production capacity
commenced in the year. Works
are underway to increase the total
daily fluids handling capacity
from approximately 32,000 bbl to
52,000 bbl of total fluids, which will
increase oil production and mitigate
natural production decline.
In PPL 207 (30% interest) the
Worrior-11 development well drilled
in December 2016 was brought
online to produce from the lower
Birkhead Formation and upper Hutton
Sandstone. Production fell below
expectations and the well was later
shut in, with subsequent analysis
showing that the reservoir had been
swept of material oil volumes.
The Operator continues to evaluate
exploitation opportunities in the
Worrior field to arrest natural
production decline.
In the northern Cooper Basin permits
PEL 90K (25% interest), PRLs 207-209
(19.165% interest) and PRLs 183-190
(20% interest), the Operator conducted
a detailed regional prospectivity
review that will potentially identify
drilling opportunities.
1 The PEL 92 Joint Venture (Cooer Energy
25% interest) holds 10 Petroleum Production
Licences and 28 Petroleum Retention Leases:
PRL’s 85-104 (all of which were originally
licenced as PEL 92). The PEL 100 Joint
Venture (Cooper Energy 19.165%) holds 3
Petroleum Retention Leases: PRL’s 207-209
(all of which were originally licenced as PEL
100). The PEL 110 Joint Venture (Cooper
Energy 20%) holds 8 Petroleum Retention
Leases: PRL’s 183-190 (all of which were
originally licenced as PEL 110).
21
Review of Operations
Otway Basin – Onshore
Kingston SE
SOUTH AUSTRALIA
Naracoorte
ROBE TROUGH
Robe
PEL 494 (30%)
PRL 32 (30%)
Cooper Energy tenement
Gas field
Gas pipeline
Depositional trough
PE
N
O
LA
ST CLAIR TROUGH
Beachport
Millicent
Penola
Katnook
Nangwarry
T
R
O
U
G
H
VICTORIA
PEP 171 (25%)
Mount Gambier
ARDONAC
HIE T
R
O
U
G
H
Hamilton
PEP 150 (20%)
PEP 168 (50%)
Plan area
TAS
0
20
40
kilometres
Portland
Warrnambool
Cobden
SHIPWRECK
TROUGH
Otway 58AR17
Cooper Energy holds interests in four
exploration licences and one retention
licence in the onshore Otway Basin,
covering a total area of 7,292 km:
PEL 494 undertaken during the
year has enhanced delineation
and high-grading of conventional
drilling opportunities.
- a 30% interest in the PEL 494
and PRL 32, Penola Trough, South
Australia;
- a 25% interest in PEP 171, Penola
Trough, Victoria;
- a 20% interest in PEP 150, Victoria,
and
- a 50% interest in PEP 168, Victoria.
The company’s primary focus in the
onshore Otway Basin is exploration
for oil and 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, has
assisted identification of a number of
opportunities for future evaluation of
the deep plays in the Penola Trough.
Reprocessing and interpretation of
the Haselgrove, Balnaves and
St George 3D seismic surveys in
22
Applications to suspend and extend
PEPs 150, 168 and 171 for a further
12 months due to the ongoing
moratorium on onshore conventional
gas exploration were submitted to
the Victorian regulatory authority.
Prior to year-end the Victorian
government passed legislation to
amend the Petroleum Act 1998 to
indefinitely ban hydraulic fracture
stimulation and to extend the
moratorium on petroleum exploration
and production in onshore Victoria
until 30 June 2020.
Cooper Energy and its joint venture
partners are also currently reviewing
their longer term options and plans
for onshore permits in Victoria in light
of the state government’s extension
to a moratorium on onshore
petroleum activities.
International
Cooper Energy completed its
withdrawal from activities outside
Australia during FY17.
Indonesia
Cooper Energy sold its remaining
Indonesian interest, a 55% stake
in the Tangai-Sukananti KSO
onshore South Sumatra Basin during
the year. The sale, to Bass Oil
Limited, involved total consideration
of $5.7 million, comprised of initial
$500,000 and 180,000,00 shares
in Bass Oil Limited with the remaining
$2.27 million in deferred payments
with the final payment to be
received before December 2018,
and receivables as they fall due.
Cooper Energy’s share of oil
production from its Indonesian
operations in FY17 prior to divestment
was 25.6 kbbl.
Tunisia
Cooper Energy ceased operations
in Tunisia during the year, consistent
with its strategy of focusing resources
on its opportunities in Australia.
The company’s 30% interest in the
Bargou permit was transferred to joint
venture partner Dragon Oil Limited
after the completion of the Hammamet
West-3 well abandonment work
obligation.
The company agreed terms with the
Hammamet Joint Venture in respect
of an outstanding dispute.
The terms of the settlement does
not require a firm cash payment by
Cooper Energy. However, should
the Hammamet Joint Venture elect to
withdraw from the permit, Cooper
Energy will fund a 35% share of any
agreed exit fee up to an agreed,
undisclosed, ceiling. Cooper Energy
previously held a 35% interest in
the Hammamet Joint Venture prior to
its withdrawal in June 2015.
23
Health Safety Environment
and Community (HSEC)
In Cooper Energy
HSEC is embodied
in the word “care” and
consideration for this
is a priority in all our
decisions and actions.
Care is a core Cooper Energy value
and, consistent with this the effective
management of Health, Safety,
Environment and Community is an
essential and integral part of the way
in which Cooper Energy manages its
operations and activities. The HSEC
Management System is Cooper
Energy’s Corporate System, which
provides the framework for the
delivery of the Company’s values
related to health, safety, environment
and community.
The second half of the financial year
has been one of momentous change
for Cooper Energy in the HSEC area
as it has evolved from a company
primarily undertaking non-operated
activities in Australia together with
land based operations in South
Sumatra, Indonesia to a fully-
fledged Operator of newly acquired
offshore subsea gas producing
assets in Victoria and taking on full
responsibility for the Sole offshore
gas development. Consequently,
the company’s HSEC Management
Systems and processes have
undergone transformational change,
with the commitment of considerable
resources to develop and implement
the necessary systems, processes
and procedures to support the
operational change.
Health and Safety
Cooper Energy staff and contractors
worked a total of 501,000 hours in
FY17, with a single minor medical
treatment injury in Indonesia,
resulting in a Total Recordable Case
Frequency Rate for the year of 1.98
events per million hours. There were
no lost time injuries. This compares
to the zero recordable cases and
24
zero lost time injuries in the previous
year. While the FY17 result does not
match the previous year’s result of
zero recordable cases and medical
treatment cases, the incident and
injury free performance with this
one minor exception is a noteworthy
achievement.
Environment Management Plans.
Significant work has gone into
developing and implementing this
system for compliance with legislative
and regulatory requirements whilst
also being fit for purpose for the
needs of a relatively small and
growing company.
Our focus during FY18 will be on
embedding the HSEC Management
System into the corporate
culture, ensuring compliance
with regulatory obligations and
operating in accordance with
best industry practice. Two areas
of particular attention will be
audit and management of key
contractors, notably those involved
with the offshore drilling campaign
scheduled to start from the March
quarter 2018.
Community and Values
In Cooper Energy our values
are a key input to all we do,
including recruitment of our staff
and contractors. The Cooper
Energy values are care, integrity,
fairness and respect, transparency,
collaboration, awareness and
commitment. We endeavour to live
these values in all we do.
Cooper Energy has a long term
commitment to contribute to, and
engage with, the communities in
which we operate. An example is the
“Making a Difference” volunteering
program in Adelaide, where Cooper
Energy staff contributed their
time and resources to a variety of
charitable organisations which have
relevance and meaning to our staff
and contractors. This program will
be broadened to other locations
where Cooper Energy now operates.
Environment
There were no recordable
environmental incidents in our
operated activities during the
financial year. Our focus during
FY18 will be to maintain this
record; ensure compliance with the
obligations set out in Environment
Plans; ensure staff and contractors
are fully trained to effectively
manage any environmental
incidents; and ensure continuous
improvement in processes and
performance in this area. To support
this process the company is mindful
of, and taking account of, best
practice and lessons from others
in the upstream oil and gas sector
and other relevant industries.
Management Systems
Development
The change in Cooper Energy
during the year was largely due to
the assumption of responsibilities as
Operator of the Sole, Casino Henry
and Patricia-Baleen gas projects
offshore Victoria. A key element
of this transition has been the
development and implementation of
the HSEC Management System that
underpins activities. This system
comprises the company’s Policies,
Standards, Standard Instructions
and Operating Procedures, together
with various offshore regulatory
and safety critical documents such
as Safety Cases, Environment Plans,
Offshore Pollution Emergency Plans,
Emergency Response Plans, Well
Operations Management Plans
and Pipeline Integrity Management
Plans and the onshore equivalent
Safety Management Plans and
Site workers at Orbost Gas Plant
25
Portfolio
Exploration and Production Tenements
Region: Australia
Cooper Basin
State
Tenement
Interest
Location
Area (km2)
Operator
Activities
South Australia PPL 204 (Sellicks)
25%
Onshore
2.0
Beach Energy
Production
PPL 205
(Christies / Silver Sands)
PPL 207 (Worrior)
PPL 220 (Callawonga)
PPL 224 (Parsons)
PPL 245 (Butlers)
PPL 246 (Germein)
PPL 247 (Perlubie)
PPL 248 (Rincon)
PPL 249 (Elliston)
PPL 250 (Windmill)
PEL 90 (Kiwi sub-block)
ex PEL 92 1
PEL 93
ex PEL 100 2
ex PEL 110 3
25%
30%
25%
25%
25%
25%
25%
25%
25%
25%
25%
25%
30%
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
Onshore
4.3
6.4
5.5
1.8
2.1
0.1
1.5
2.0
0.8
0.6
Beach Energy
Production
Senex Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Beach Energy
Production
Onshore
144.6
Senex Energy
Exploration
Onshore
1889.3
Beach Energy
Exploration
Onshore
621.8
Senex Energy
Exploration
19.17%
Onshore
296.5
Senex Energy
Exploration
20%
Onshore
727.5
Senex Energy
Exploration
Otway Basin
State
Tenement
Interest
Location
Area (km2)
Operator
Activities
30%
30%
10%
50%
50%
50%
50%
50%
20%
50%
25%
10%
Onshore
Onshore
Onshore
1274
Beach Energy
Exploration
36.9
58.0
Beach Energy
Exploration
BHP
Production
Offshore
199.0
Cooper Energy
Production
Offshore
200.0
Cooper Energy
Production
Offshore
127.0
Cooper Energy
Retention
Offshore
6.0
Cooper Energy
Retention
Offshore
599.0
Cooper Energy
Exploration
Onshore
3,212.0
Beach Energy
Exploration
Onshore
795.0
Beach Energy
Exploration
Onshore
1,974.0
Beach Energy
Exploration
Onshore
n/a
BHP
Gas Processing
South Australia
PEL 494
PRL 32
VIC/L22
VIC/L24
VIC/L30
VIC/RL11
VIC/RL12
VIC/P44
PEP 150
PEP 168
PEP 171
Minerva Gas Plant
Victoria
26
Gippsland Basin
State
Tenement
Interest
Location
Area (km2)
Operator
Activities
Victoria
Orbost Gas Plant
100%4
Onshore
n/a
Cooper Energy4
VIC/L21
100%
Offshore
134.0
Cooper Energy
Gas Processing
(undergoing upgrade
for Sole gas project)
Production
(suspended)
VIC/RL13
VIC/RL14
VIC/RL15
VIC/L32
100%
100%
100%
100%
Offshore
Offshore
Offshore
67.0
67.0
67.0
Cooper Energy
Retention
Cooper Energy
Retention
Cooper Energy
Retention
Offshore
201.0
Cooper Energy
Development
(for Sole gas project)
1 ex PEL 92 consists of PRLs; 85, 86, 87, 88, 89, 90, 92, 92, 93, 94, 95, 96, 97, 98, 99, 100, 101, 102, 103 and 104.
2 ex PEL 100 consists of PRLs; 207, 208 and 209.
3 ex PEL 110 consists of PRLs; 183, 184, 185, 186, 187, 188, 189 and 190.
4 this interest is to be acquired by APA Group pursuant to agreement announced 1 June 2017.
Orbost gas plant, centre view shows elevated conduit guides for horizontal directional drill.
27
Board of
Directors
28
Chairman
Mr John C. Conde AO
B Sc B.E(Hons), MBA
Independent Non-Executive Director
Appointed 25 February 2013
Independent
Non-Executive Director
Mr Jeffrey W. Schneider
B.Com
Appointed 12 October 2011
Experience and expertise
Mr Schneider has over 30 years of
experience in senior management roles
in the oil and gas industry, including
24 years with Woodside 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
During the reporting period, Mr Schneider
was Chairman of the Remuneration and
Nomination Committee and member of the
Audit and Risk Committee.
From 1 July 2017, the duties of the Audit
and Risk Committee were separated
into two stand-alone committees being the
Audit Committee and the Risk and
Sustainability Committee. Mr Schneider
is a member of both the Risk and
Sustainability Committee and the Audit
Committee.
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 Bupa Australia
(since 2008) and 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
Destination NSW (2011 – 2014) 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. During the reporting period he
was a member of the Remuneration and
Nomination Committee and the Audit
and Risk Committee.
From 1 July 2017, the duties of the Audit
and Risk Committee were separated
into two stand-alone committees being the
Audit Committee and the Risk and
Sustainability Committee. Mr Conde is
a member of the Audit Committee.
Independent
Non-Executive Director
Ms Alice J. M. Williams
B.Com FAICD, FCPA, CFA
Appointed 28 August 2013
Non-Executive Director
Mr Hector M. Gordon
B Sc (Hons). FAICD
Appointed 24 June 2017
Executive Director
26 June 2012 – 23 June 2017
Managing Director
Mr David P. Maxwell
M Tech FAICD
Appointed 12 October 2011
Experience and expertise
Ms Williams has over 25 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 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 Limited ASX: EQT
(since 2007), Djerriwarrh Investments
Limited, Victorian Funds Management
Corporation (since 2008), Barristers
Chambers Limited (since 2015), the
Foreign Investment Review Board (since
2015) and Defence Health. Ms Williams
is a former council member of the
Cancer Council of Victoria and former
non-executive Director of Guild Group,
Racing Victoria Limited and Port of
Melbourne Corporation.
Special Responsibilities
During the Reporting period, Ms Williams
was Chairman of the Audit and Risk
Committee and a member of the
Remuneration and Nomination Committee.
From 1 July 2017, the duties of the Audit
and Risk Committee were separated into
two stand-alone committees being the
Audit Committee and the Risk and
Sustainability Committee. Ms Williams
is the Chairman of the Audit Committee
and a member of the Risk and
Sustainability Committee.
Experience and expertise
Mr Gordon is a 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 the Company.
Special Responsibilities
As a part-time executive of the Company,
Mr Gordon was responsible for overseeing
exploration and production activities and
providing technical expertise in these
areas. He ceased being an executive
director at the end of the term of his
executive services agreement on 23 June
2017 and became a Non-Executive
Director on 24 June 2017.
From 1 July 2017, the duties of the Audit
and Risk Committee were separated
into two stand-alone committees being the
Audit Committee and the Risk and
Sustainability Committee. Mr Gordon
is the Chairman of the Risk and
Sustainability Committee and a member
of the Audit Committee.
Experience and expertise
Mr Maxwell is a leading oil and gas
industry executive with more than 30 years
in senior executive roles with companies
such as BG Group, Woodside Petroleum
Limited and Santos Limited. Mr Maxwell
has very successfully led many large
commercial, marketing and business
development projects.
Prior to joining Cooper Energy
Mr Maxwell worked with the BG Group,
where he was responsible for all
commercial, exploration, business
development, strategy and marketing
activities in Australia and led BG Group’s
entry into Australia and Asia including a
number of material acquisitions.
Mr Maxwell has served on a number
of industry association boards,
government advisory Groups and public
Company boards.
Current and other directorships in
the last 3 years
Mr Maxwell is a director of wholly-owned
subsidiaries of Cooper Energy Limited.
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.
29
Executive
Management
Team
Managing Director
David Maxwell
M. Tech FAICD
Chief Financial Officer
Virginia Suttell
B.Com ACA GAICD, Grad Dip ACG
David Maxwell has over 30 years’
experience as a senior executive with
companies such as BG Group, Woodside
and Santos. As Senior Vice President at
QGC, a BG Group business, he led BG’s
entry into Australia, its alliance with and
subsequent takeover of QGC. Roles at
Woodside included director of gas and
marketing and membership of Woodside’s
executive committee.
Virginia Suttell is a chartered accountant
with more than 20 years’ experience,
including 16 years in publicly listed
entities, principally in group finance and
secretarial 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. Other previous
appointments include Group Financial
Controller at Austereo Group Limited.
Company Secretary and
Legal Counsel
Alison Evans
BA LLB
General Manager, Commercial
and Business Development
Eddy Glavas
B.Acc CPA, MBA
Ms Alison 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.
Eddy Glavas has more than 18 years’
experience in business development,
finance, commercial, portfolio management
and strategy, including 14 years in oil and
gas. 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.
30
General Manager, Development
Duncan Clegg
PhD - Soil Mechanics, BSc Engineering
General Manager, Operations
Iain MacDougall
Bsc (Hons)
Duncan Clegg has over 35 years’
experience in upstream and midstream
oil and gas development, including
management positions at Shell and
Woodside, leading oil and gas
developments including FPSO, subsea
and fixed platform developments.
At Woodside, he held several senior
executive positions including Director
of the Australian Business Unit, Director
of the African Business Unit and CEO
of the North West Shelf Venture.
Iain MacDougall has more than 28 years’
experience in the upstream petroleum
exploration and production sector. His
experience includes senior management
positions with independent operators
and wide ranging international experience
with Schlumberger. In Australia, his
previous roles include Production and
Engineering Manager and then acting
CEO at Stuart Petroleum prior to the take-
over by Senex Energy.
General Manager, Exploration
and Subsurface
Andrew Thomas
BSc (Hons)
Andrew Thomas is a successful
geoscientist with over 28 years’ experience
in oil and gas exploration and development
in companies including Geoscience
Australia, Santos, Gulf Canada and
Newfield Exploration. At Newfield he was
SE Asia New Ventures Manager and
Exploration Manager for offshore Sarawak.
General Manager, Projects
Michael Jacobsen
B Eng (Hons)
Michael 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. In that time Michael
has been responsible for the delivery/
project management of a number of
successful offshore petroleum projects
including most recently Fletcher Finucane
and Henry/Netherby.
31
Key Performance Indicators
Operational
Production
12 months
to 30 June
MMboe
Proved and probable reserves MMboe
Wells drilled
number
Exploration wells spudded
number
2009
2010
2011
2012
2013
2014
2015
2016
2017
0.49
1.91
7
5
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
Reserve replacement ratio
percent
196%
11%
134%
-113%
98%
71%
333%
18%
768%
Financial
Sales revenue
Other revenue
EBITDA
Profit before tax
$ million
41.6
40.0
39.1
59.6
53.4
72.3
39.1
27.4
39.1
$ million
$ million
$ million
4.2
5.2
5.0
4.3
8.0
7.2
1.2
5.1
(6.0)
(5.5)
(10.3)
Profit after tax / (loss)
$ million
(2.8)
Cash and term deposits
$ million
93.4
92.5
72.4
Investments
Working capital
Accumulated profit
$ million
$ million
$ million
Cumulative franking credits
$ million
-
96.5
23.2
17.7
-
95.4
24.4
25.7
-
79.5
14.1
31.4
4.7
9.1
21.0
8.4
61.5
13.2
53.4
22.5
37.0
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)
47.9
20.2
51.7
23.8
39.0
49.1
26.0
41.2
39.4
49.8
147.5
1.9
1.0
0.7
43.0
44.2
84.0
45.7
(17.7)
(52.6)
(64.9)
38.7
43.7
42.9
42.9
Shareholders equity
$ million
123.3
125.1
114.9
136.9
137.2
167.8
103.9
91.6
285.0
Earnings per share
cents
(1.0)
0.4
(3.5)
2.8
0.4
6.4
(19.2)
(10.1)
(1.8)
Return on shareholders funds
percent
-2.3%
1.0%
-8.6%
6.7%
0.9%
14.4% -46.7% (-38.0)%
-6.5%
Total shareholder return
percent
(3.2)% (17.8)% (2.7)%
25.0% (16.7)%
34.7% (51.5)% (12.2)%
72.7
Average oil price
A$/bbl
86.76
87.02
95.42
114.63
112.31
124.08
85.48
60.75
61.89
Capital as at 30 June
Share price
Issued shares
$ per share
0.45
0.37
0.36
0.45
0.375
0.505
0.245
0.215
0.38
million
291.9
292.6
292.6
327.3
329.1
329.2
331.9
435.2 1,140.2
Market capitalisation
$ million
131.4
108.3
105.3
147.3
123.4
166.3
81.4
93.6
433.3
Shareholders
number
7,596
6,537
5,573
5,485
5,284
5,122
5,103
4,931
6,292
32
Cooper Energy Limited and its controlled entities
Financial Report
For the year ended 30 June 2017
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 Earnings per share
7 Cash and cash equivalents and term deposits
8
9
Trade and other receivables
Prepayments
10 Equity instruments at fair value through other
comprehensive income
11 Discontinued operations and assets held for sale
12 Investments in associate
13 Asset acquisition
14 Oil and gas assets
15 Impairment
16 Property, plant and equipment
17 Exploration and evaluation
18 Trade and other payables
19 Provisions
20 Financial liabilities
21 Contributed equity and reserves
22 Financial risk management objectives and policies
23 Hedge accounting
24 Commitments and contingencies
25 Interests in joint arrangements
26 Related parties
27 Share based payment plans
28 Auditors remuneration
29 Parent entity information
30 Events after the reporting period
Directors’ Declaration
Independent Audit Report
Auditors’ Independence Declaration
Securities Exchange and Shareholder Information
Shareholder Information
34
44
46
66
67
68
69
70
70
83
86
87
90
91
92
93
93
94
95
95
96
97
97
98
98
99
100
100
102
105
106
107
108
110
113
113
114
115
116
124
125
126
Corporate Directory Inside back cover
33
Operating and Financial Review
For the year ended 30 June 2017
Summary Overview
Cooper Energy has concluded the 2017 financial year (“FY17” or “the year”) having fundamentally changed its revenue profile, size, asset
portfolio and geographical focus and capital structure.
The Company is now focussed entirely on Australia and generates the majority of its income from gas production in south-east Australia.
Gas also accounts for the majority of the Company’s expanded reserves and resources base. Annual production increased 109% and is
expected to grow by approximately five times in three years to 2020 through projects that are currently in development.
Market capitalisation of $433 million at 30 June compares with the corresponding figure of $96 million at the commencement of the
year. This development can be attributed to four milestone events completed under the Company’s strategy to focus on Australia and in
particular gas:
• the acquisition of gas production, exploration and development assets in the Otway and Gippsland basins, offshore Victoria. The assets
acquired saw Cooper Energy assume 100% ownership of the Sole gas field and Orbost Gas Plant and 50% ownership of the offshore
Otway Basin assets;
• agreement with APA Group, whereby they will acquire, upgrade and operate the Orbost Gas Plant to process gas from the Sole gas field;
• Board approval of the Sole gas project as ready to proceed in March 2017 with the final investment decision (FID) made by the Board
subsequent to 30 June 2017 as a result of significant advancements towards achieving full funding of the project; and
• concentration of the Company’s portfolio on Australia with the sale of remaining Indonesian assets and withdrawal from Tunisia.
Cooper Energy has now completed the establishment phase of its strategy to build a gas business around a portfolio of gas projects and
supply contracts focussed on south-east Australia. The Company’s portfolio now encompasses a mixture of gas supply contracts, market
competitive producing assets, plant, development projects underway and under consideration, and well-located exploration acreage
with an inventory of attractive prospects. These assets have the capacity to generate growth in reserves, production and revenue for
several years.
The financial significance of the year’s progress is only partially evident in the accounts for the twelve months to 30 June, initially because
the acquisition of producing assets was effective from 1 January 2017 and, more significantly, because the greatest uplift in revenue
generation is forecast to occur from the closing six months of FY19. The accounts are thus those of a transition year, incorporating a half-
year’s production from the acquired gas assets, and contract, portfolio and capital management initiatives associated with the Sole gas
project that were still in progress at 30 June.
The Company recorded a statutory loss for the period of $12.3 million, of which $3.6 million is due to significant items, mainly
impairments recorded against Indonesian assets held for sale and penalty provisions associated with the Company’s exit from Tunisia.
Exclusive of these significant items, Cooper Energy recorded an underlying loss of $8.7 million. Analysis of these and other results,
including comparison with previous periods, appears under the heading ‘Financial Performance’ later in this report.
Operations
Cooper Energy is a petroleum exploration and production company which generates revenue from the supply of gas to south-east Australia
and oil production in the Cooper Basin. The Company’s current interests and operations include:
• offshore gas and gas liquids production in the Otway Basin, Victoria, from the Casino Henry and Minerva gas assets;
• onshore oil production and exploration from the western flank of the Cooper Basin;
• development projects in the Gippsland Basin to supply gas to south-east Australia;
• onshore and offshore gas exploration in the Otway Basin; and
• offshore gas exploration in the Gippsland Basin.
The Company has Operator responsibilities for offshore gas production and exploration in the Otway Basin and offshore gas exploration
and development in the Gippsland Basin.
At 30 June 2017 the Company had 26.9 full time equivalent (FTE) employees and 14.1 FTE contractors compared with 20.1 FTE
employees and 3.6 FTE contractors at the beginning of the year. FTE and contractor numbers increased after year end with the
assumption of operator responsibilities from Santos effective from 1 July 2017. Headcount at that date was 31.6 FTE employees and 45.6
FTE contractors.
Safety
A single recordable case injury occurred during the period, resulting in a Total Recordable Case Frequency Rate (TRCFR) of 1.98 for the
12 months to 30 June 2017 which is better than industry average. No lost time incidents were recorded.
Production
Cooper Energy produced 0.96 million barrels of oil equivalent (MMboe) in FY17, comprising 4.0 PJ of gas and 0.28 million barrels
(MMbbl) of crude oil and condensate, which compares to the previous year’s production of 0.46 MMbbl of oil. The movement in
oil volume between periods is attributable to the divestment of Indonesian operations effective from 30 September 2016 and lower
production from the Cooper Basin, where the suspension of drilling in the previous year was reflected in lower output. Results achieved
from the resumption of drilling in the Cooper Basin during FY17 are expected to maintain production levels in FY18.
34
Operating and Financial Review
For the year ended 30 June 2017
Operations continued
Reserves and resources
Reserves and Contingent Resources as at 30 June 2017 were reported to the ASX on 29 August 2017.
Proved and Probable (“2P”) Reserves at 30 June totalled 11.7 MMboe compared with 3.0 MMboe twelve months earlier. The principal
factors in the movement were:
• addition of 10.6 MMboe from the acquisition of the Casino Henry and Minerva gas assets;
• revisions to Cooper Basin 2P oil reserves that resulted in net 0.8 MMbbl upgrade to estimates. The major contributor to this upgrade
was reserves upgrades for the Callawonga field following the successful 5-well drilling campaign during the year;
• removal of 1.7 MMboe attributable to Indonesian operations divested during the year; and
• production of 0.96 MMboe.
Contingent Resources (2C) at 30 June were 78 MMboe, 23% higher than at the beginning of the year. The movement in Contingent
Resources is the result of:
• the addition of 21.9 MMboe in the Sole gas field through acquisition of the 50% interest not held previously;
• addition of 3.2 MMboe in the Otway Basin through recognition of Cooper Energy’s share of the Black Watch gas field, VIC/RL11 and
VIC/RL12 and through plant inlet pressure reductions at the Iona Gas Plant;
• removal of 17.4MMboe attributable to Tunisian and Indonesian interests divested during the year; and
• a net increase in Cooper Basin Contingent Resources.
Gas marketing
The development, contracting and supply of gas to south-east Australia is a core element of the Company’s strategy to create value for its
shareholders. The marketing of this gas is being conducted to optimise returns whilst assuring cash flow and revenue through contracting
a base load of gas under longer term contracts and marketing the balance in a mixture of shorter term agreements.
The objective of the Company’s gas marketing efforts in FY17 was to contract sufficient gas from the Sole gas field necessary to support
financing of development. This objective was achieved in January 2017 at which point 180 PJ of the Company’s 249 PJ 2C Resource had
been contracted to a portfolio of gas buyers including AGL Energy, EnergyAustralia, Alinta Energy and O-I Australia. It is expected that
marketing of uncontracted gas from Sole will be pursued once the Sole finance arrangements are finalised.
The Company also holds uncontracted gas at Casino Henry (52PJ of 2P Reserves) and Manta (106 PJ 2C Resources). Marketing of
uncontracted gas from Casino Henry is now underway. Marketing of Manta gas will be coordinated with the development plans for
the field.
Exploration and development
Otway Basin
The Company holds offshore and onshore interests in the Otway Basin, the most significant of which are the Casino Henry and Minerva
gas projects and the VIC/P44 exploration permit located offshore Victoria. Interests are held in onshore acreage in South Australia and
Victoria, with activity in the latter suspended due to the Victorian government’s moratorium on onshore gas exploration.
Transfer of operatorship and the majority of the titles in relation to the offshore Otway Basin acreage occurred subsequent to year end.
Transfer of title for a few of the pipeline licences is pending approval from the relevant regulators.
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 100% interest in VIC/L32, which holds the Sole gas field;
• a 100 % interest in VIC/RL13, VIC/RL14 and VIC/RL15, which holds the Manta gas field. Manta is assessed to contain 2C Resources
of 106 PJ of gas and 3.2 MMbbl of liquids as well as hydrocarbon potential in deeper reservoirs; and
• a 100% interest in VIC/RL22 which contains the largely depleted and shut-in Patricia-Baleen gas field, and infrastructure offering
connection to the Orbost Gas Plant.
The Company is working towards 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 comprises:
• an offshore development to be conducted by Cooper Energy comprising the drilling and completion of two production wells, the
installation of gas pipeline and control umbilicals to connect field; operations to the Orbost Gas Plant via a horizontally drilled shore
crossing. Abandonment of the Sole-2 appraisal well will also be conducted; and
• an onshore development comprising the upgrade of the Orbost Gas Plant by APA Group to process gas from Sole.
35
Operating and Financial Review
For the year ended 30 June 2017
Operations continued
The project schedule is for the delivery of first gas from the field into the upgraded plant in March 2019 and supply of sales gas from the
plant from around June 2019.
Work on the offshore project to date has concentrated on the shore crossing and finalisation of the planning and preparations for further
work which is scheduled to commence in the FY18 second half with drilling operations.
The offshore development is estimated to involve capital expenditure of $355 million, approximately 62% of which is under fixed price contracts.
Manta gas project
It is intended the Manta gas and liquids field be developed to utilise economies available through integration with Sole and, potentially, the
Patricia-Baleen gas field and pipeline.
Commercialisation of the gas field was found to be economically feasible in 2015 by a formal business case study and a development
concept involving 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.
Events during FY17 have enhanced the economics and certainty of Manta project development:
• gas market forecasts indicate a tighter gas supply outlook for south-east Australia and the level of enquiry and prices on offer from
buyers has increased;
• development costs have been ascertained to have reduced substantially through the process of price discovery and tendering for the
Sole gas project. Development costs for Manta are now estimated to be $309 million;
• access and terms for processing of Manta gas at the Orbost Gas Plant has been agreed with the proposed plant owner APA Group; and
• Cooper Energy’s acquisition of the Patricia-Baleen gas field and the pipeline linking the field with the Orbost Gas Plant.
It is expected that a firm development plan for the field will be completed following the results from drilling Manta-3, which is proposed to
appraise the known gas-bearing reservoirs and test prospective resources in deeper reservoirs underlying those previously drilled.
Cooper Basin
Drilling activity, which had been suspended in FY16 due to the low oil price environment, recommenced during the year. A total of nine
wells were spudded in the Company’s Cooper Basin acreage. Of the nine wells drilled, seven were successful development wells and were
cased and suspended. The final five of these wells, which also had appraisal objectives, were drilled on the Callawonga oil field to address
the McKinlay Member sandstone which has hitherto been lightly exploited. The success of this program has been reflected in upgrades to
reserves estimates and investigation of a possible further drilling program in the new calendar year.
The remaining wells, Penneshaw-1, an oil exploration well in PRL 87, and Butlers-9, an oil appraisal well in PPL 245, were plugged
and abandoned.
36
Operating and Financial Review
For the year ended 30 June 2017
Financial Performance
Cooper Energy recorded a statutory loss after tax of $12.3 million for the financial year which compares with the loss after tax of $34.8
million recorded in the 2016 financial year. The 2017 statutory loss includes a number of items which adversely affected the loss after tax
by a total of $3.6 million. These items principally comprise impairments to the Indonesian oil property assets held for sale and a provision
for the exit of the Hammamet permit in Tunisia (both included in discontinued operations).
Financial Performance
Sales volume
Sales revenue
Gross profit
Gross profit / Sales revenue
Operating cash flow
Reported loss
Underlying loss
Underlying EBITDA*
MMboe
$ million
$ million
%
$ million
$ million
$ million
$ million
FY17
0.951
39.1
16.6
42.5
4.1
-12.3
-8.7
5.3
FY16
0.451
27.4
9.9
36.1
7.9
-34.8
-2.8
1.2
Change
0.500
11.7
6.7
6.4
-3.8
22.5
-5.9
4.1
%
111%
43%
68%
18%
-48%
65%
-211%
342%
* Earnings before interest, tax, depreciation and amortisation
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 loss after tax (exclusive of impairments to the Indonesian oil property assets, gain on sale of the Indonesian subsidiary and
Tunisian exit provision) was $8.7 million, compared with an underlying loss after tax of $2.8 million in the 2016 financial year. The factors
which contributed to the movement between the periods were:
• higher sales revenue of $11.7 million as a result of gas produced from the assets acquired during the period;
• higher amortisation costs, $5.8 million, mainly due to amortisation on gas assets acquired;
• higher exploration and evaluation expenditure written off, $1.9 million, due to unsuccessful wells drilled in the 2017 financial year;
• higher non-cash finance costs and restoration expenses of $2.3 million, due to rehabilitation relating to the assets acquired during
the period;
• higher general administration and other costs of $3.9 million, due to integration costs brought about by the acquisition of the Victorian
assets, consulting and new venture costs, costs associated with the closure of discontinued operations and increased staff costs; and
• higher tax expense of $4.2 million including PRRT payments made in respect of the Company’s producing gas assets.
37
Operating and Financial Review
For the year ended 30 June 2017
Financial Position
Financial Position
Total assets
Total liabilities
Total equity
Total Assets
$ million
$ million
$ million
FY17
492.6
207.6
285.0
FY16
176.3
84.8
91.6
Change
316.3
122.8
193.4
%
179%
145%
211%
Total assets increased by $316.3 million from $176.3 million to $492.6 million.
At 30 June the Company held cash and deposit balances of $147.5 million, equity investments of $0.7 million and no debt.
Cash and deposit balances increased by $97.7 million over the period after net proceeds from equity issues of $201.9 million and cash
flows from operations of $4.1 million partially offset by the acquisition of the Victorian gas assets of $65.0 million and funding exploration
and development expenditure of $42.3 million as summarised in the chart below.
$ million
Total cash &
investments
50.8
-42.1
-65.0
Total cash &
investments
148.2
201.9
-1.2
0.7
Investments
(at fair value)
Investments
(at fair value)
1.0
49.8
Cash &
deposits
-14.6
27.0
-3.4
-2.8
1.6
-3.7
147.5
Cash &
deposits
Operating
+4.1
53.9
Other
+93.6
June 16 Operations General Net
Tax
Admin Working
Capital
Movement
Exit
Penalties
Interest Cash Proceeds E & D Aquisitions FX & June 17
after
from
operating equity
issues
cash flows
of oil & gas Other
assets
Exploration and evaluation assets increased $112.3 million from $111.0 million to $223.3 million as a result of expenditure on Gippsland
Basin assets and the acquisition of the Victorian exploration gas assets.
Oil and gas assets increased by $64.0 million from $5.4 million to $69.4 million mainly as a result of the acquisition of the Victorian gas
assets and capital expenditure incurred on development activities in the Cooper Basin.
Trade and other receivables increased $10.5 million from $3.4 million to $13.9 million, mainly due to the timing of sales revenue receipts
and consideration receivable for the sale of Sukananti to the Company’s associate.
38
Operating and Financial Review
For the year ended 30 June 2017
Financial Position continued
Total Liabilities
Total liabilities increased by $112.8 million from $84.8 million to $207.6 million.
Trade and other payables increased $50.5 million from $8.0 million to $58.5 million mainly due to $20.0 million of contingent
consideration payable for the Victorian gas asset acquisition and accrued costs relating to capital expenditure.
Provisions increased by $49.4 million from $69.6 million to $119.0 million due to rehabilitation provisions assumed on acquisition of
the Victorian gas assets.
Total Equity
Total equity has increased by $193.4 million from $91.6 million to $285.0 million. In comparing equity for the period to the prior
corresponding period the key movements were:
• higher contributed equity of $205.6 million due to shares issued from equity raisings and shares issued on vesting of performance
rights during the period; and
• higher reserves of $0.2 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 swaps for which cash flow hedge relationships apply; offset in part by
• higher accumulated losses of $12.3 million due to the reported loss for the period.
Business Strategies and Prospects
Since 2012 Cooper Energy has been pursuing a strategy aimed at concentrating the Company’s efforts and resources on building a
gas business that can participate in gas supply opportunities foreseen arising in south-east Australia. The progress made in FY17 has
taken Cooper Energy to the point where it has the portfolio of gas reserves and resources, development projects and gas contracts to
fulfil this strategy and to record substantial growth in production revenue and shareholder value through its execution.
This will be achieved through:
• conducting operations safely and with due care for the employees, communities and environments in which we operate;
• increasing revenue and margin generation from existing gas operations in the Otway Basin through contracting and portfolio
management of uncontracted gas and improved operational outcomes;
• efficient and value-accretive development and production of oil and gas from existing operations in the Cooper Basin;
• value-adding to the Manta gas project through the drilling of the Manta-3 appraisal and exploration well and progression of the
development proposal to the point of commitment;
• assessment, exploration and appraisal of the attractive gas prospects in the Company’s offshore acreage; VIC/P44 in particular is highly
prospective for gas and presents favourable development economics through the proximity of pipeline and processing infrastructure;
• the addition of new production brought by completion of the Sole gas project to commence supply from mid-2019; and
• vigilance for value-accretive growth opportunities that meet the Company’s acquisition criteria, in particular value creation through
application of Cooper Energy’s gas commercialisation and/or offshore operator credentials.
Market conditions are supportive of the Company’s prospects for executing and generating value from its strategy. Gas supply to south-
east Australia is anticipated to remain tight and the Company’s uncontracted gas in the Otway and Gippsland basins continues to attract
enquiries and interest from gas buyers.
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.
39
Operating and Financial Review
For the year ended 30 June 2017
Business Strategies and Prospects continued
Outlook
Cooper Energy anticipates production of approximately 1.4 MMboe from its operations in FY18. The large majority of this figure is forecast
to come from Otway Basin gas production with approximately 0.2 MMboe from the Cooper Basin oil production.
The Company continues to manage general and administration costs tightly while advancing commercialisation of the Gippsland Basin
gas projects. General and administration cost estimates for FY18 are now expected to be approximately $14 million.
Capital expenditure guidance for FY18 is for cash expenditure of approximately $224 million accounted for by:
• Gippsland Basin expenditure of $204 million, chiefly being development expenditure of $203 million on the Sole gas project;
• Otway Basin expenditure of $9 million being development expenditure, the major item of which is workover of the Casino-5
production well;
• Cooper Basin expenditure of $7 million, including the drilling of 3 exploration wells, the drilling of 5 development wells, and field
connections and facilities upgrade at Callawonga; and
• other expenditure of approximately $4 million.
As at 30 June the Company had oil price hedge arrangements in place for 0.03 MMbbl over the next 6 months. In respect of the balance
of FY18, the effect of the positions taken is that approximately 27% of the Company’s first half oil production is hedged at an average floor
price of A$54.45/bbl. The Company does not currently hedge for gas price or foreign currency exchange risk.
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 and investments of $148.2 million. On 29 August 2017 the Company announced a fully
underwritten accelerated non renounceable entitlement offer to raise approximately $135.0 million, subject to standard market terms.
On this date, the Company also announced its execution of binding underwritten commitments for $250.0 million under a senior reserve
based lending facility to be used for the purposes of debt funding a portion of the Sole gas field development costs. Further information
is detailed in Notes 7 and 30 of the Financial Statements.
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
Description
1
Exploration
2
Development and
Production
40
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 includes 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.
Operating and Financial Review
For the year ended 30 June 2017
Risk Management continued
Risk
Description
3
Regulatory
4 Market
Cooper Energy operates in a highly regulated environment. Cooper Energy endeavours to comply with the
regulatory authorities requirements. There is a risk that regulatory approvals are withheld, take longer than
expected or unforeseen circumstance arise where requirements are not met and costs may be incurred
to remediate non compliance and/or obtain approval(s). Changes in 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 all stakeholder
concerns are addressed fairly and managed. Policies and procedures are independently reviewed and
audited to help ensure they are appropriate and comply with all regulatory requirements.
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 monitors developments and changes in the international oil and domestic gas market and
conducts regular risk assessments to enable the Company to be best placed to address changes in
market conditions.
5
Oil and gas prices
Future value, growth and financial condition 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.
6
Operating
7
Counterparties
8
Reserves
9
Environmental
10 Funding
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.
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 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 and requirements.
Cooper Energy must undertake significant capital expenditures in order to conduct its development appraisal
and exploration activities. Limitations on the accessing 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 that the best source of funding to maximise shareholder benefits and
having regard to prudent risk management is obtained and is supported by economic and commercial
analysis of all business undertakings.
41
Operating and Financial Review
For the year ended 30 June 2017
Risk Management continued
Risk
Description
11 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 loss to Underlying net loss and Underlying EBITDA
Reconciliation to Underlying loss
Net loss after income tax
Adjusted for:
Impairment of discontinued operations
Exit provision
Impairment of exploration and evaluation
Impairment of investment in associate
Gain on sale of subsidiary
Tax impact of above changes
Underlying loss
Reconciliation to Underlying EBITDA*
Underlying loss
Add back:
Interest revenue
Accretion expense
Tax expense / (benefit)
Depreciation
Amortisation
Underlying EBITDA*
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
$ million
FY17
-12.3
1.0
4.0
0.0
0.0
-1.4
0.0
-8.7
FY17
-8.7
-1.6
2.5
2.9
0.3
9.8
5.3
FY16
-34.8
13.0
3.7
21.7
0.2
0.0
-6.5
-2.8
FY16
-2.8
-0.8
1.4
-1.2
0.5
4.1
1.2
Change
22.5
-12.0
0.3
-21.7
-0.2
-1.4
6.5
-5.9
Change
%
65%
-92%
8%
-100%
-100%
-100%
100%
-211%
%
-5.9
-211%
-0.8
1.1
4.1
-0.2
5.7
4.1
-100%
79%
342%
-40%
139%
342%
* Earnings before interest, tax, depreciation and amortisation
42
Operating and Financial Review
For the year ended 30 June 2017
Reconciliations of other measures to the Financial Statements
Reconciliation to sales volumes
Continuing operations
MMboe
Add back: Indonesia held for sale / discontinued operations MMboe
Sales volume
Reconciliation to sales revenue
Continuing operations
MMboe
$ million
Add back: Indonesia held for sale / discontinued operations
$ million
Sales revenue
Reconciliation to gross profit
Continuing operations
$ million
$ million
Add back: Indonesia held for sale / discontinued operations
$ million
Gross profit
$ million
Reconciliation to gross profit / sales revenue
Continuing operations
Add back: Indonesia held for sale / discontinued operations
Gross profit / Sales revenue
%
%
%
Reconciliation to production expenses and royalties
Continuing operations
$ million
Add back: Indonesia held for sale / discontinued operations
$ million
Production expenses and royalties
$ million
Reconciliation to amortisation
Continuing operations
$ million
Add back: Indonesia held for sale / discontinued operations
$ million
Amortisation
Reconciliation to general administration
Continuing operations
$ million
$ million
Add back: Indonesia held for sale / discontinued operations
$ million
General administration
Reconciliation to tax benefit
Continuing operations
Tax impacts of adjustments to underlying loss
$ million
$ million
$ million
Add back: Indonesia held for sale / discontinued operations
$ million
Tax benefit / (expense)
$ million
FY17
0.873
0.078
0.951
FY17
34.6
4.5
39.1
FY17
14.6
1.9
16.5
FY17
42.2
42.2
42.2
FY17
10.2
2.5
12.7
FY16
0.311
0.140
0.451
Change
0.562
-0.062
0.500
FY16
Change
20.3
7.2
27.4
14.3
-2.7
11.7
FY16
Change
8.1
1.8
9.9
6.5
0.1
6.6
FY16
Change
39.9
25.0
36.1
2.3
17.2
6.1
FY16
Change
9.3
4.1
13.4
0.9
-1.6
-0.7
FY17
FY16
Change
9.8
0.1
9.9
FY17
15.4
0.4
15.8
2.9
1.2
4.1
6.9
-1.1
5.8
FY16
Change
10.8
0.9
11.7
4.6
-0.5
4.1
FY17
FY16
Change
-2.8
0.0
-0.1
-2.9
7.9
-6.5
-0.2
1.2
-10.7
6.5
0.1
-4.1
%
181%
-44%
111%
%
70%
-38%
43%
%
80%
6%
67%
%
6%
69%
17%
%
10%
-39%
-5%
%
238%
-92%
141%
%
43%
-56%
35%
%
-135%
-100%
-50%
-342%
43
Directors’ Statutory Report
For the year ended 30 June 2017
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 2017, and the independent auditor’s report thereon.
1. Directors
The Directors of the parent entity at any time during or since the end of the financial year are:
Mr John C. Conde AO
B.Sc. B.E(Hons), MBA
Chairman
Independent Non-Executive
Director
Appointed 25 February 2013
Mr David P. Maxwell
M.Tech, FAICD
Managing Director
Appointed 12 October 2011
Experience and expertise
Mr Conde has extensive experience in business and commerce and in chairing high profile business,
arts and sporting organisations.
Previous positions include non-executive Director of BHP Billiton, Chairman of Pacific Power (the
Electricity Commission of NSW), Chairman of 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 Bupa Australia (since 2008) and 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 Destination NSW (2011 – 2014) 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. During the reporting period he was a member of the
Remuneration and Nomination Committee and the Audit and Risk Committee.
From 1 July 2017, the duties of the Audit and Risk Committee were separated into two stand-alone
committees being the Audit Committee and the Risk and Sustainability Committee. Mr Conde is a
member of the Audit 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.
44
Director’s Statutory Report
For the year ended 30 June 2017
1. Directors continued
Mr Hector M. Gordon
B.Sc. (Hons). FAICD
Executive Director
26 June 2012 – 23 June 2017
Non-Executive Director
Appointed 24 June 2017
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 the Company.
Special Responsibilities
As a part time executive of the Company, Mr Gordon was responsible for overseeing exploration
and production activities and providing technical expertise in these areas. After he ceased being an
executive director at the end of the term of his executive services agreement on 23 June 2017,
Mr Gordon became a Non-Executive Director on 24 June 2017.
From 1 July 2017, the duties of the Audit and Risk Committee were separated into two stand-alone
committees being the Audit Committee and the Risk and Sustainability Committee. Mr Gordon is the
Chairman of the Risk and Sustainability Committee and a member of the Audit Committee.
Mr Jeffrey W. Schneider
B.Com
Independent Non-Executive
Director
Experience and expertise
Mr Schneider has over 30 years of experience in senior management roles in the oil and gas industry,
including 24 years with Woodside Petroleum Limited. He has extensive corporate governance and board
experience as both a non-executive director and chairman in resources companies.
Appointed 12 October 2011
Current and other directorships in the last 3 years
Ms Alice J. M. Williams
B.Com, FAICD, FCPA, CFA
Independent Non-Executive
Director
Appointed 28 August 2013
Mr Schneider is a former director of Comet Ridge Limited ASX: COI (2003 – 2014).
Special Responsibilities
During the reporting period, Mr Schneider was Chairman of the Remuneration and Nomination
Committees and member of the Audit and Risk Committee.
From 1 July 2017, the duties of the Audit and Risk Committee were separated into two stand-alone
committees being the Audit Committee and the Risk and Sustainability Committee. Mr Schneider is
a member of both the Risk and Sustainability Committee and the Audit Committee.
Experience and expertise
Ms Williams has over 25 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 and Racing Victoria
Limited (since 2016). 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
During the Reporting period, Ms Williams was Chairman of the Audit and Risk Committee and a
member of the Remuneration and Nomination Committee.
From 1 July 2017, the duties of the Audit and Risk Committee were separated into two stand-alone
committees being the Audit Committee and the Risk and Sustainability Committee. Ms Williams is the
Chairman of the Audit Committee and a member of the Risk and Sustainability Committee.
45
Director’s Statutory Report
For the year ended 30 June 2017
2. Company secretaries
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.
Mr Jason de Ross was appointed to the position of Company Secretary on 25 November 2013. Mr de Ross resigned as Company
Secretary when his employment with the Company ceased on 9 December 2016.
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
Audit & Risk
Committee
Meetings*
Remuneration and
Nomination Committee
Meetings
Mr J. Conde
Mr D. Maxwell
Mr H. Gordon
Mr J. Schneider
Ms A. Williams
A
17
17
17
17
17
B
17
17
17
17
17
A
4
-
-
4
4
B
4
-
-
4
4
A
2
-
-
2
2
B
2
-
-
2
2
A = Number of meetings attended.
B = Number of meetings held during the time the Director held office, or was a member of the committee, during the year
*From 1 July 2017, the duties of the Audit and Risk Committee were separated into two stand-alone committees being the Audit
Committee and the Risk and Sustainability Committee.
4. Remuneration Report
Information about the remuneration of the Company’s key management personnel for the financial year ended 30 June 2017 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 2017 for which we will seek your support at the 2017 Annual General Meeting.
The report is designed to provide information regarding our remuneration framework and the outcomes for the reporting period.
Report context: 2017 Financial Year
The Company’s performance in the 12 months to 30 June 2017 is reported in the Operating and Financial Review of the Financial Report
and discussed in the Managing Director’s report and Chairman’s report found in this Annual Report. It is not necessary to repeat this
detail, but there are features I highlight in introducing this Remuneration Report.
Cooper Energy recorded transformational growth in its production, proved and probable reserves and business base in the 2017 financial
year. The progress of the company’s gas strategy was accelerated, such that by year end, Cooper Energy was established as a gas supplier
to south-east Australia and had commenced construction of its major growth opportunity, the Sole gas project. The company’s position is
now such that it can reasonably anticipate further growth in revenue, production and reserves in the 2018 financial year.
Importantly, the company valuation also recorded transformational growth rising from a market capitalisation of approximately $96 million
at 30 June 2016 to over $400 million at the conclusion of the year. For shareholders, a total shareholder return of 72.7% was recorded,
outperforming the company’s peer group for the reporting period.
The Committee believes it is relevant that this performance was achieved through the disciplined application of the Company’s gas
strategy by its management team over several years. In this context, the Board believes that the remuneration framework, which
incentivises long term value adding performance has been effective in retaining, motivating and rewarding the existing team and delivering
value for you, our shareholders.
46
Director’s Statutory Report
For the year ended 30 June 2017
4. Remuneration Report continued
Developments
The completion of the Victorian gas asset acquisition effective from 1 January changed the balance of the income source from oil to gas;
brought expanded management responsibilities; and necessitated a reset of scorecard performance measures.
The management team was restructured effective from 1 January 2017. This involved revision of the roles and responsibilities of each
member of the Executive KMP to cover the new activities undertaken by the gas business that had been developed including increased
responsibilities, and larger functional teams. The team’s capability was also strengthened with the addition of Duncan Clegg as General
Manager, Development and Virginia Suttell as Chief Financial Officer. Since year end, Michael Jacobsen has further enhanced our
technical leadership as General Manager Projects.
In view of the results achieved at the half year and the change in business, from 1 January 2017 fixed remuneration of Executive KMP
was reinstated to the levels in place prior to reductions taken in response to the lower oil price environment. At the same time, salaries
of the Executive KMP were reviewed against industry benchmarks taking into account the revised scope of position descriptions and
the changed size and nature of the Company. This resulted in some members of the team receiving market adjustments to ensure
remuneration was market competitive and consistent with the remuneration policy.
Non-Executive Directors had also reduced their Directors’ fees during the previous financial year. Fees were reinstated from 1 January
2017 to prior levels and following a benchmark review, they were also increased for the first time since 2013. The Non-Executive Directors
also increased in number with the appointment of Hector Gordon.
We thank the Managing Director, the management team and all our people 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 FY17 performance and KMP outcomes
4.5 Nature of Executive KMP remuneration
4.6 Nature of Non-Executive KMP remuneration
4.7 Statutory remuneration disclosures
Page
47
47
48
49
53
57
58
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;
• Executive Directors; and
• the executives on the management team.
47
Director’s Statutory Report
For the year ended 30 June 2017
4. Remuneration Report continued
4.2 Key Management Personnel covered in this Report continued
Executive Directors 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
Position
Dates
Current
Mr J. Conde AO
Mr J. Schneider
Ms A. Williams
Mr H. Gordon
Executive KMP
Current
Mr D. Maxwell
Mr A. Thomas
Mr E. Glavas
Ms A. Evans
Mr I. MacDougall
Ms V. Suttell
Mr D. Clegg
Former
Mr H. Gordon
Mr J. de Ross
Chairman
Non-executive Director
Non-executive Director
Non-executive Director
Position
Full reporting period
Full reporting period
Full reporting period
From 24 June 2017
Dates
Managing Director
General Manager Exploration & Subsurface
Exploration Manager
Full reporting period
From 1 January 2017
Until 31 December 2016
General Manager Commercial & Business Development
Commercial and Business Development Manager
From 1 January 2017
Until 31 December 2016
Company Secretary and Legal Counsel
Full reporting period
General Manager Operations
Operations Manager
Chief Financial Officer (Acting)
General Manager Development
From 1 January 2017
Until 31 December 2016
18 January 2017 – 30 June 2017
From 1 May 2017
Executive Director – Exploration & Production
Until 23 June 2017
Chief Financial Officer and Company Secretary
Until 9 December 2016
Ms Suttell was appointed Chief Financial Officer on 1 July 2017. Mr Michael Jacobsen was appointed as General Manager Projects on
1 July 2017. Mr Jacobsen had previously been leading the Sole development project team for Santos and his employment transferred at
the time operatorship of the Sole assets was transferred to Cooper Energy. Both Ms Suttell and Mr Jacobsen are part of the management
team and accordingly are Executive KMP for the purposes of this Report.
4.3 Remuneration Governance
4.3.1 Philosophy and objectives
The Company is committed to a remuneration philosophy that aligns to our 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.
48
Director’s Statutory Report
For the year ended 30 June 2017
4. Remuneration Report (Audited) continued
4.3 Remuneration Governance continued
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 & Nomination Committee
The Company’s Remuneration & 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 Remuneration 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 FY17 performance and Executive KMP pay outcomes
4.4.1 Remuneration actually delivered to Executives in FY17 (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.
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 2016 being the STIP awarded for performance during the prior period (FY16);
• the market value of shares issued in FY17 on the vesting of performance rights granted November 2013 and April 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.
49
Director’s Statutory Report
For the year ended 30 June 2017
4. Remuneration Report continued
4.4 FY17 performance and Executive KMP pay outcomes continued
4.4.1 Remuneration actually delivered to Executives in FY17 (not audited) continued
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 J. de Ross5
2017
2016
2017
2016
2017
2016
2017
2016
2017
2016
2017
2016
2017
2016
2017
2016
2017
2016
667,500
350,000
422,608
650,000
275,000
93,907
231,718
85,000
245,348
219,502
80,500
51,922
381,762
96,000
152,824
375,123
96,000
78,681
107,620
-
223,274
176,089
374,411
382,025
297,764
281,190
386,803
-
-
-
48,000
47,500
96,000
87,000
77,000
62,000
-
-
68,040
9,419
88,930
-
-
-
-
-
31,500
-
176,868
86,000
411,691
335,276
85,000
28,433
88,691
83,350
6,466
6,373
6,192
5,824
2,453
-
6,603
6,236
6,649
6,419
6,466
6,373
92
-
3,240
6,373
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,528,799
1,102,257
568,532
358,297
636,778
555,628
110,073
-
345,917
239,244
565,990
475,444
381,230
349,563
418,395
-
283,371
961,170
-
455,082
1. Mr Gordon worked part time during the reporting period (0.5 full time equivalent) and accordingly his entitlements are prorated.
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 (0.7 full time equivalent for the period 1 July 2016 to 31 January 2016 and 0.8 full time equivalent for the
period 1 February 2017 to 30 June 2017) 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 de Ross left employment on 9 December 2016. His termination payment included the payout of unused annual leave entitlements.
LTIP includes the accelerated vesting of performance rights granted under the 2011 Plan that had been tested and achieved at the
time of termination and pro-rata vesting of performance rights and share appreciation rights granted under the EIP based on service
and performance.
50
Director’s Statutory Report
For the year ended 30 June 2017
4. Remuneration Report continued
4.4 FY17 performance and Executive KMP pay outcomes continued
In addition to the amounts set out in the table above, Executive KMP were also delivered a STI cash bonus in FY17 in respect of the first
half of the FY17 financial year measurement period for the Company’s STIP.
STI payments are generally made for performance over a 12 month period, however the acquisition of the Victorian gas assets from
Santos (which was not foreseen at the time the FY17 company scorecard was approved by the Board) was an extraordinary event which
transformed the Company and necessitated a re-set of the scorecard performance measures (which were increased because most
measures had already been exceeded from 1 January). An interim STIP award was made to employees in January 2017. The interim STIP
payments made to Executive KMP are set out below.
Name
Executive Directors
Mr D. Maxwell
Mr H. Gordon
Executives
Mr A. Thomas
Ms A. Evans
Mr I. MacDougall
Mr E. Glavas
Mr J. de Ross
HY17 STIP
$
293,940
70,171
78,400
51,320
78,400
66,360
50,953
The STIP for the second half of the financial year will be assessed in accordance with the Company’s usual timeframes and will be paid in
October 2017.
4.4.2 Cooper Energy five-year performance
12 months to 30 June
2013
2014
2015
2016
2017
Annual production
Proved & Probable Reserves
MMboe
MMboe
TRCFR1
Financial
Sales revenue
Profit after tax
Earnings per share
Total shareholder return
Capital as at 30 June
Share price
Market capitalisation
events per hours worked
$ million
$ million
cents
percent
0.49
2.16
2.10
53.4
1.3
0.4
(16.7)
0.59
2.01
2.52
72.3
22.0
6.4
34.7
$ per share
$ million
0.375
123.4
0.505
166.3
1. Total Recordable Case Frequency Rate
0.48
3.08
4.18
39.1
(63.5)
(19.2)
(51.5)
0.245
81.4
0.46
3.00
0.00
27.4
(34.8)
(10.1)
(12.2)
0.215
93.6
0.96
11.7
1.98
39.1
(12.3)
(1.8)
72.7
0.38
433.4
51
Director’s Statutory Report
For the year ended 30 June 2017
4. Remuneration Report continued
4.4 FY17 performance and Executive KMP pay outcomes continued
4.4.3 STIP outcomes
The most significant achievement during the performance period was the acquisition of the Victorian gas assets from Santos which was
effective from 1 January 2017. The acquisition had a significant impact on all of the key measures in the Company Scorecard. The Board
awarded an interim short term incentive payment relating to performance over the first half of the financial year and then re-set the
scorecard for the remaining half of the financial year with increased performance measures that reflected the transformed business.
Performance 1 July to 31 December 2016
Performance against the Company Scorecard for the period 1 July to 31 December 2016 was determined by the Board as follows:
Performance measures in
company scorecard
Performance 1 July to 31
December 2016
Comment
HSEC Performance
Super Stretch
0.0 Total Recordable Case Frequency Rate and a 0.0 Lost time
Injury Frequency Rate. This is an excellent result and better
than industry benchmarks. In addition, many of the Company’s
environmental and safety systems and processes were enhanced
as the Company prepared to become an operator of producing
assets in Australia.
Increased production
Super Stretch
Production increased 3 times above year end forecast.
Growth in reserves
and resources
Key gas strategy milestones
Super Stretch
Acquisitions and divestments
Cost management
Processes and
Risk Management
People and stakeholder
relationships
Super Stretch
A significant increase in reserves and resources with the
addition of 10.6 MMboe from the acquisition of the Casino
Henry and Minerva gas assets. The Company’s gas strategy
was accelerated. The exit from Tunisia was completed and the
Company had entered into agreements to exit Indonesia in
accordance with strategy.
Costs were within budget and processes and systems
significantly upgraded. The Company undertook a very
successful capital raising to fund the acquisition of Victorian
gas assets.
Excellent performance against all measures (both against the Company Scorecard and individual performance measures) resulted in the
delivery of between Stretch and Super Stretch (i.e. maximum award) to Executive KMP in relation to the first half of the reporting period.
The amounts that were paid in January 2016 are set out in Section 4.4.1.
Performance 1 January to 30 June 2017
In re-setting the scorecard, the Board maintained the same broad categories of performance measures but increased the relevant targets.
The key changes were to:
• recognise increased HSEC requirements in becoming an operator of producing assets in offshore Australia;
• increase reserves and production growth targets;
• recognise that as operator of producing assets in Australia, the Company would have increased regulatory and other responsibilities; and
• recognise the increased funding requirements for Cooper Energy as 100% owner of the Sole gas project.
The preliminary Scorecard results for the second half of the reporting period ranged between Target and Super Stretch. The final STIP
results for the second half of the reporting period, in conjunction with individual performance reviews will be determined in September
and form the basis of individual STIP payments in October 2017.
52
Director’s Statutory Report
For the year ended 30 June 2017
4. Remuneration Report continued
4.4 FY17 performance and Executive KMP pay outcomes continued
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 2018.
-100%
-50%
0%
50%
100%
150%
200%
Share Price Performance - 15 December 2015 to 30 June 2017
Cooper Energy Limited
172%
193%
129%
32%
-7%
-19%
-20%
-24%
-28%
-49%
-51%
-61%
-62%
During the reporting period, shares were issued to Executive KMP on the vesting of performance rights granted in October 2013 and
March 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
Start VWAP
End VWAP
Cooper Energy TSR
TSR Rank
Absolute TSR Achieved
Relative TSR Achieved
Award 5 (granted October 2013)
Award 6 (granted March 2014)
0.3965
0.3004
-24.26%
0.5361
0.3004
-43.97%
1st against peer group
1st against peer group
0.00%
100.00%
0.00%
100.00%
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).
53
Director’s Statutory Report
For the year ended 30 June 2017
4. Remuneration Report continued
4.5 Nature of Executive KMP remuneration continued
The Company’s remuneration profile for Executive KMP is as follows:
Remuneration
Element
Expressed as percentage of base remuneration
at target level performance
Expressed as percentage of base remuneration at
maximum (super stretch) level performance
Managing
Director
Executive
Director
Fixed Remuneration
STIP (at risk)
LTIP 1 (at risk)
Total
100%
50%
120%
270%
4.5.1 Fixed Remuneration
100%
38%
95%
233%
Other
Executive
KMP
100%
25%
70%
195%
Managing
Director
Executive
Director
100%
100%
120%
320%
100%
75%
95%
270%
Other
Executive
KMP
100%
50%
70%
220%
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 2017 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 Execute 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 100%
Executive Director 75%
50%
Executives
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 generally operates over a 12 month
performance period from 1 July to 30 June.
Due to the impact on the scorecard of the acquisition of the Victorian gas assets from Santos
(which transaction was effective from 1 January 2017), the Board determined to re-set the
Company scorecard at 1 January 2017. Performance was therefore measured against the initial
scorecard at the end of December 2016 and against the re-set scorecard at the end of June
2017. See further information in section 4.4.3.
1 Reflects face value of LTIP at grant date however may not necessarily reflect the amount that will ultimately vest and be exercised.
54
Director’s Statutory Report
For the year ended 30 June 2017
4. Remuneration Report continued
4.5 Nature of Executive KMP remuneration continued
4.5.1 Fixed Remuneration continued
How are the performance measures
determined and what are their
relative weightings?
When are STIP payments made?
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 target 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: 80% Company: 20% individual
• Executive 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.
STIP payments, if any, are generally made in October each year. As discussed above however
in the 2017 financial year the STIP payments were in two halves. The first STIP payment
was made in January and any STIP payments in respect of the second half will be paid in
October 2017.
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). It is proposed that future grants will be made under the EIP. The key features of the
grants made in the financial year 2017 (granted October 2016) 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 Director
Executive KMP
Senior staff
120%
95%
70%
50%
55
Director’s Statutory Report
For the year ended 30 June 2017
4. Remuneration Report continued
4.5 Nature of Executive KMP remuneration continued
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 is 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.
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: Beach Energy Limited; Senex Energy Limited; Blue
Energy Limited; Tap Oil Limited; Central Petroleum Limited, AWE Limited, Icon Energy Limited,
Buru Energy Limited, Carnarvon Petroleum Limited, Strike Energy Limited, Empire Oil & Gas NL
and Horizon Oil Limited.
The peer group was based on a group of ASX-listed companies in the energy and resources
sector, with Australian operations and a range of market capitalisation. The peer group is
reviewed annually for relevance and amended as appropriate.
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).
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
and grants are now made under the EIP. The 2011 Plan is referred to in this Report because
some Executive KMP still hold performance rights granted under the 2011 Plan. The last of the
performance rights granted under the 2011 Plan will be tested in the 2018 financial year.
56
Director’s Statutory Report
For the year ended 30 June 2017
4. Remuneration Report continued
4.5 Nature of Executive KMP remuneration continued
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.
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.
Mr Hector Gordon – Executive Director Exploration and Production
Mr Gordon commenced as Executive Director Exploration and Production on 26 June 2012 under a contract of employment. Mr Gordon’s
contract expired on 23 June 2017. From 24 June 2017, Mr Gordon was appointed as a Non-Executive Director.
Deeds of indemnity
The Company also entered into deeds of indemnity, insurance and access with each of the Executive Directors under which the Company
will, on the terms set out in the deed, provide an indemnity, maintain an appropriate level of Directors’ & 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 not currently fully utilised.
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 increase in Non-Executive Directors fees reflects the reinstatement of the 10% reduction in fees taken by the Non-
Executive Directors in the 2016 financial year in response to the lower oil price environment. In addition, the Non-Executive Directors fees
were increased from 1 January 2017 for the first time since 2013 following a review that compared Non-Executive Director fees with peer
group companies.
The Company has entered into written letters of appointment with its Non-Executive Directors. The term of the appointment of a Non-
Executive Director is determined in accordance with the Company’s Constitution and is subject to the provisions of the Constitution dealing
with retirement, re-election and removal of Non-Executive Directors. The Constitution provides that all Non-Executive Directors of the
Company are subject to re-election by shareholders by rotation every three years.
The Company has entered into 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’ & Officers’ indemnity
insurance and provide access to Company records.
57
Director’s Statutory Report
For the year ended 30 June 2017
4. Remuneration Report (Audited) continued
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 12 September 2016. 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 4.6 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
2017
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
2017
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
2017
Executive Directors
Mr D. Maxwell
Mr H. Gordon
Executives
Mr A. Thomas
Ms V. Suttell
Ms A. Evans
Mr I. MacDougall
Mr E. Glavas
Mr D. Clegg
Mr J. de Ross1
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
-
-
-
-
-
-
-
- 1,190,446
53% 1,178,643 $333,556
691,121
48% 341,554 $96,660
430,490
45% 421,369 $119,247
-
-
Nil
-
191,662
37% 213,908 $60,536
234,025
29% 404,089 $114,357
-
-
-
-
-
Nil
Nil
-
-
-
-
-
-
-
-
- 3,044,232 $459,679
-
882,177 $133,209
- 1,088,323 $164,337
-
-
Nil
-
552,487 $83,426
- 1,043,693 $157,598
-
-
-
Nil
Nil
300,318 $84,990
775,670 $117.126
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
- 608,920
57%
- 233,975
33%
- 660,415
33%
The vesting date of the performance rights granted on 8 December 2016 is 8 December 2019. The fair value of these rights is $0.283
per right. These performance rights have a commencement date of 12 September 2016.
The vesting date of the share appreciation rights granted on 8 December 2016 is 8 December 2019. The fair value of these rights is
$0.151 per right. These share appreciation rights have a commencement date of 12 September 2016.
1 2011 Plan includes the accelerated vesting of performance rights that had been tested and achieved at the time of termination of
employment. EIP includes the pro-rata vesting of performance rights and share appreciation rights based on service and performance at
the time of termination.
58
Director’s Statutory Report
For the year ended 30 June 2017
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 2016
Granted
Lapsed
Vested &
Exercised
Held at
30 June 2017
Directors
Mr D. Maxwell
Mr H. Gordon
Executives
2,913,301
1,270,086
Mr A. Thomas
1,047,545
Ms V. Suttell
Ms A. Evans
Mr I. MacDougall
Mr E. Glavas
Mr D. Clegg
Mr J. de Ross
-
475,429
808,722
338,039
-
926,523
-
-
-
-
-
-
-
-
-
274,118
159,140
1,190,446
1,448,737
691,121
419,825
99,126
430,490
517,929
-
44,133
78,008
-
-
-
191,662
234,025
-
-
317,603
608,920
-
239,634
496,689
338,039
-
-
Performance Rights
(EIP)
Held at
1 July 2016
Granted
Lapsed
Vested &
Exercised
Held at
30 June 2017
Directors
Mr D. Maxwell
Mr H. Gordon
Executives
Mr A. Thomas
Ms V. Suttell
Ms A. Evans
Mr I. MacDougall
Mr E. Glavas
Mr D. Clegg
Mr J. de Ross
2,228,571
1,178,643
645,810
341,554
796,722
421,369
-
383,370
764,050
567,840
-
709,017
-
213,908
404,089
300,318
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
475,042
233,975
The performance rights lapsed during the period noted in the table above were granted in December 2015.
3,407,214
987,364
1,218,091
-
597,278
1,168,139
868,158
-
-
59
Director’s Statutory Report
For the year ended 30 June 2017
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 2016
Granted
Lapsed
Vested &
Exercised
Held at
30 June 2017
Directors
Mr D. Maxwell
Mr H. Gordon
Executives
6,290,322
3,044,232
1,822,850
882,177
Mr A. Thomas
2,248,812
1,088,323
Ms V. Suttell
Ms A. Evans
Mr I. MacDougall
Mr E. Glavas
Mr D. Clegg
Mr J. de Ross
-
1,082,094
2,156,592
1,602,774
-
2,001,259
-
552,487
1,043,693
775,670
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,340,844
660,415
9,334,554
2,705,027
3,337,135
-
1,634,581
3,200,285
2,378,444
-
-
The share appreciation rights lapsed during the period noted in the table above were granted in December 2015.
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 2016
Purchases
Received on
vesting of
performance
rights
Sales
Held at
30 June 2017
Directors
Mr J. Conde AO
272,728
340,910
-
3,309,333
3,678,877
1,190,446
Mr D. Maxwell
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
469,610
322,728
52,728
361,227
-
61,174
-
-
-
200,000
403,410
65,910
989,647
29,000
177,664
293,567
-
135,000
-
691,121
-
-
430,490
-
191,662
234,025
-
-
-
Mr J. de Ross1
372,375
Options
No options were issued (or forfeited) during the year.
1 No longer KMP.
60
-
-
-
-
-
-
-
-
-
-
-
-
613,638
8,178,656
1,360,731
726,138
118,638
1,781,364
29,000
430,500
527,592
-
135,000
-
Director’s Statutory Report
For the year ended 30 June 2017
4. Remuneration Report continued
4.7 Statutory remuneration disclosures continued
4.7.3 Table of Directors’ remuneration for 2016 and 2017 financial years
Base
Salary &
Fees
$
Directors
Mr J. Conde AO 2017
161,644
2016
137,595
Mr J. Schneider 2017
103,402
2016
81,697
Benefits
Short-term
STIP
Other
Short-term
Benefits(a)
Long
Term
Long
Service
Leave
$
-
-
-
-
$
-
-
-
-
$
-
-
-
-
Mr D. Maxwell
2017
647,884 498,421
88,691
38,938
2016
630,692
342,388
83,350
Mr H. Gordon
2017
212,241
113,472
6,466
2016
200,194
93,997
6,373
Ms A. Williams
2017
103,402
2016
81,697
-
-
-
-
-
-
-
-
-
Post
Employment
Share Based
Remuneration(c)
Superannuation(b)
LTIP
Total
$
15,356
13,072
9,823
7,761
19,616
19,308
19,476
19,308
9,823
7,761
$
-
-
-
-
$
177,000
150,667
113,225
89,458
554,317
1,847,867
517,092
1,592,830
179,088
530,743
220,606
540,478
-
-
113,225
89,458
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 26 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.
61
Director’s Statutory Report
For the year ended 30 June 2017
4. Remuneration Report continued
4.7 Statutory remuneration disclosures continued
4.7.4 Table of Executives’ remuneration for 2016 and 2017 financial years
Benefits
Short-term
Base
Salary
STIP
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
$
$
$
$
$
$
$
$
2017
362,147 128,902
6,192
14,494
19,616
198,431
- 729,782
2016
355,815
98,798
5,824
19,308
186,377
- 666,122
Ms V. Suttell
2017
98,673
26,330
2,453
2016
-
-
-
-
-
8,947
-
-
-
- 136,403
-
-
Ms A. Evans
Mr I.
MacDougall
2017
203,658
82,521
6,603
9,134
19,616
95,395
- 416,927
2016
156,781
46,278
6,236
-
19,308
81,046
- 309,649
2017
354,796
127,084
6,649
32,245
19,616
146,609
- 686,999
2016
362,717
100,616
6,419
Mr E. Glavas
2017
278,148
113,328
6,466
2016
261,882
74,777
6,373
Mr D. Clegg (d)
2017
383,534
21,201
2016
-
-
92
-
Mr J. de Ross (e)
2017
158,367
49,031
3,240
2016
315,968
87,922
6,373
-
-
-
-
-
-
-
19,308
128,013
- 617,073
19,616
122,724
- 540,282
19,308
65,299
- 427,639
3,269
31,500
- 439,596
-
-
-
-
18,501
67,696
283,371 580,206
19,308
162,930
- 592,501
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 26 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) 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.
e) Mr de Ross left employment on 9 December 2017. His termination payment included the payout of unused annual leave entitlements.
End of remuneration report.
62
Director’s Statutory Report
For the year ended 30 June 2017
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 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
Cooper Energy Limited
Ordinary Shares
Performance Rights
Share Appreciation Rights
613,638
8,178,656
1,360,731
726,138
118,638
-
4,855,951
1,407,189
-
-
-
9,334,554
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 5,300,196 outstanding performance rights granted to employees under the 2011 Plan and 10,994,298
outstanding performance rights and 30,118,716 share appreciation rights under the Equity Incentive Plan approved by shareholders at
the 2015 AGM.
During the financial year 5,073,140 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 2017.
12. Events after financial reporting date
Refer to Note 30 of the Notes to the Financial Statements.
13. Proceedings on behalf of the Company
No person has applied to the Court under section 237 of the Corporations Act 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.
63
Director’s Statutory Report
For the year ended 30 June 2017
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 124 and forms part of the Directors’ report for the financial year ended
30 June 2017.
17. Non-audit services
The amounts paid to the auditor of the Group, Ernst & Young and its related practices for non-audit services provided during the year was
$65,000 (2016: $18,540).
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 29 August 2017
64
Cooper Energy Limited and its controlled entities
Financial Statements
For the year ended 30 June 2017
65
Consolidated Statement of Comprehensive Income
For the year ended 30 June 2017
Continuing Operations
Revenue from sales
Cost of sales
Gross profit
Other revenue
Exploration and evaluation expenditure written back/(off)
Finance costs
Impairment
Share of loss in associate
Other expenses
Loss before tax
Income tax benefit
Petroleum Resource Rent Tax expense
Total tax (expense)/benefit
Consolidated
2017
$’000
2016
$’000
Notes
4
4
4
4
15
12
4
5
34,648
20,257
(20,058)
(12,180)
14,590
8,077
1,614
(1,577)
(2,555)
850
292
(1,411)
-
(21,865)
(533)
(18,574)
(7,035)
4,786
(7,598)
(2,812)
(87)
(11,851)
(25,995)
7,907
-
7,907
Net loss after tax from continuing operations
(9,847)
(18,088)
11
(2,465)
(12,312)
(16,751)
(34,839)
Discontinued operations
Loss for the year from discontinued operations
Total loss for the period attributable to members
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 derivatives accounted for in a hedge relationship
Reclassification during the period to profit or loss of realised hedge settlements
23
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
10
Other comprehensive expenditure for the period net of tax
(297)
(835)
736
494
(369)
237
-
(3,526)
2,526
300
(132)
(403)
(553)
(1,016)
Total comprehensive loss for the period attributable to members
(12,715)
(35,855)
Basic earnings per share from continuing operations
Diluted earnings per share from continuing operations
Basic earnings per share
Diluted earnings per share
cents
(1.4)
(1.4)
(1.8)
(1.8)
cents
(5.3)
(5.3)
(10.1)
(10.1)
6
6
6
6
The above Consolidated Statement of Comprehensive Income should be read in conjunction with the accompanying notes.
66
Consolidated Statement of Financial Position
As at 30 June 2017
Consolidated
2017
$’000
2016
$’000
Notes
Assets
Current Assets
Cash and cash equivalents
Trade and other receivables
Inventory
Prepayments
Assets classified as held for sale
Total Current Assets
Non-Current Assets
Equity instruments at fair value through other comprehensive income
Investment in associate
Trade and other receivables
Prepayments
Term deposits at banks
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
Derivative financial liabilities
Liabilities and provisions classified as held for sale
Total Current Liabilities
Non-Current Liabilities
Deferred tax liabilities
Deferred Petroleum Resource Rent Tax liability
Provisions
Financial liabilities
Total Non-Current Liabilities
Total Liabilities
Net Assets
Equity
Contributed equity
Reserves
Accumulated losses
Total Equity
7
8
9
147,425
10,878
2,000
1,902
162,205
11
25,090
187,295
658
-
2,997
911
41
4,315
69,402
3,694
49,717
3,400
-
303
53,420
4,788
58,208
790
173
-
-
91
-
5,385
708
223,331
110,976
305,349
118,123
492,644
176,331
58,520
19,188
114
77,822
25,448
8,014
4,064
1,275
13,353
645
103,270
13,998
-
2,176
1,481
99,802
3,044
104,327
-
65,548
3,059
70,783
207,597
84,781
285,047
91,550
343,161
137,558
6,777
6,571
(64,891)
(52,579)
285,047
91,550
10
12
8
9
7
5
14
16
17
18
19
23
11
5
5
19
20
21
21
21
The above Consolidated Statement of Financial Position should be read in conjunction with the accompanying notes.
67
Total
Equity
$’000
91,550
(12,312)
(403)
(52,579)
(12,312)
-
(12,312)
(12,715)
-
-
-
(64,891)
2,272
-
203,940
285,047
(17,740)
103,871
(34,839)
(34,839)
-
(1,016)
(34,839)
(35,855)
-
-
-
(52,579)
1,884
-
21,650
91,550
Consolidated Statement of Changes in Equity
For the year ended 30 June 2017
Issued Capital
Reserves
Accumulated
Losses
$’000
$’000
$’000
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
Equity issue
Balance at 30 June 2017
Balance at 1 July 2015
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 2016
137,558
-
-
-
223
1,440
203,940
343,161
115,460
-
-
-
448
21,650
137,558
6,571
-
(403)
(403)
2,049
(1,440)
-
6,777
6,151
-
(1,016)
(1,016)
1,884
(448)
-
6,571
The above Consolidated Statement of Changes in Equity should be read in conjunction with the accompanying notes.
68
Consolidated Statement of Cash Flows
For the year ended 30 June 2017
Cash Flows from Operating Activities
Receipts from customers
Payments to suppliers and employees
Exit penalties
Income tax received/(paid)
Petroleum Resource Rent Tax paid
Interest received
Net cash from operating activities
Cash Flows from Investing Activities
Transfers of term deposits
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
Payments for oil and gas assets
Net cash flows used in investing activities
Cash Flows from Financing Activities
Proceeds from equity issue
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
Consolidated
2017
$’000
2016
$’000
Notes
36,917
28,078
(27,965)
(21,851)
(3,703)
-
(2,785)
1,614
4,078
-
859
-
849
7,935
7
50
500
(32)
12,440
(32,149)
(28,910)
(1,261)
13
(65,000)
-
-
(9,937)
(3,486)
(107,797)
(19,988)
201,934
201,934
98,215
(507)
49,717
7
147,425
21,171
21,171
9,118
1,226
39,373
49,717
The above Consolidated Statement of Cash Flows should be read in conjunction with the accompanying notes.
69
1. Corporate information
The consolidated financial report of Cooper Energy Limited (the parent entity) for the year ended 30 June 2017 was authorised for issue in
accordance with a resolution of the Directors on 29 August 2017.
Cooper Energy Limited is a Company limited by shares incorporated and domiciled in Australia whose shares are publicly traded on the
Australian Securities Exchange.
The nature of the operations and principal activities of the Group are described in section 5 of the Directors’ Statutory Report.
2. Summary of significant accounting policies
a) Basis of preparation
The financial report is a general-purpose financial report, which has been prepared in accordance with the requirements of the
Corporations Act 2001 and Australian Accounting Standards and other authoritative pronouncements of the Australian Accounting
Standards Board.
The financial report has also been prepared on a historical cost basis, except for equity instruments measured at fair value through other
comprehensive income and derivative financial instruments measured at fair value. Cooper Energy Limited is a for profit Company.
The financial report is presented in Australian dollars and all values are rounded to the nearest thousand dollars ($’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.
The consolidated financial report has been prepared on a going concern basis which contemplates the continuity of normal business
activities (including generation of operating cash flows from the expanded base business) and development of the Sole gas project.
At 30 June 2017 the Group has entered into contracts for future capital expenditure commitments of $208.0 million primarily in
connection with the Sole gas project, which is in excess of the Group’s available cash and cash equivalents of $147.4 million at this date.
Cash outflows associated with these commitments over the 12 months following the date of this report are $104.0 million.
At the date of this report the Directors are satisfied there are reasonable grounds to believe that the Group will be able to continue to
meet its debts as and when they fall due and that it is appropriate for the financial statements to be prepared on a going concern basis.
Pertinent matters supporting this position are as follows:
• On 29 August 2017, the Group announced a fully underwritten entitlement offer to raise approximately $135 million, subject to standard
market terms. Together with the cash at bank as at 30 June 2017, the funds raised from the equity issue will provide sufficient liquidity
to fund its expenditure commitments, including the capital commitments relating to the Sole gas project, for more than 12 months from
the date of this report.
• The Group is in the advanced stages of finalising the external debt funding of the Sole gas project, including senior debt in the form of a
reserve based lending facility which is underwritten, and subject to conditions precedent including perfection of security, environmental
and insurance due diligence and a gas market independent review report.
• The Company is well advanced with the satisfaction of the conditions precedent under the sale agreement for the Orbost Gas Plant
to the APA Group (APA). At completion of the sale to APA, all the commitments associated with the Orbost Gas Plant upgrade will be
transferred to APA. Existing capital commitments of the Group in respect of the Orbost Gas Plant, which are reflected currently in the
capital commitments set out above, would be assumed by APA.
• The Directors regularly monitor the Group’s cash position and, on an on-going basis, consider a number of options to ensure that
adequate funding continues to be available. The Group has the capacity, if necessary, to defer discretionary expenditure in the current
cashflow forecast period of the business, or take other steps to moderate the cash outflows of the business if required.
The Directors are satisfied that the quantum of the funds to be secured via the means outlined above will be sufficient to enable the Group
to complete the development of the Sole gas project and meet the ongoing commitments of the Group.
Significant event and transaction
During the period the Group raised additional equity through two institutional placements and two retail offers (in December 2016 and
May 2017). As a result of the institutional placements, 512.2 million new shares were issued (144.2 million in December 2016 and
368.0 million in May 2017); a further 187.5 million shares were issued under the retail offers (75.4 million in December 2016 and
112.0 million in May 2017). A total of $203.9 million (net of costs and tax) was raised from the four transactions. Refer to Note 21 for
further information.
Effective 1 January 2017, the Group acquired the Victorian gas assets of Santos Limited, which established Cooper Energy as a supplier of
gas to south-east Australia. The assets acquired include:
- 50% interest in the Casino Henry joint venture in the offshore Otway Basin;
- remaining 50% interests in the Sole gas field and Orbost Gas Plant in the Gippsland Basin, increasing the Company’s interest in both
assets to 100%;
- 50% interest in gas exploration acreage in the offshore Otway Basin;
- 100% interest in the depleted Patricia Baleen gas field and associated infrastructure; and
- 10% interest in the Minerva gas project and Minerva Gas Plant.
Refer to Note 13 for further information.
70
Notes to the Financial StatementFor the year ended 30 June 2017 2. Summary of significant accounting policies continued
a) Basis of preparation continued
On 27 February 2017, the Group signed a non-binding Heads of Agreement for the sale of the Orbost Gas Plant to APA Group which
was executed on 1 June 2017. As part of the sale, the Group will receive $20 million in consideration to be held in escrow against
performance of Cooper Energy’s obligations under the agreements with APA Group. APA Group is responsible for funding capital
expenditure associated with the upgrade and development of the Orbost Gas Plant to process raw natural gas from the Sole gas field and
other gas fields. Refer to Note 11 for further information. Completion of the transaction remains subject to certain conditions.
During the period, the Group completed the withdrawal from its international operations. The Company sold its remaining Indonesian
asset to Bass Oil Limited (the Company’s associate). Activities in Tunisia ceased with the closure of the Tunisian office during the March
quarter. The only item remaining is a provision regarding the Hammamet exit. Refer to Note 11 for further information.
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.
The Group’s accounting policies are consistent with those of the previous financial year except for new policies adopted from 1 July 2016
as follows:
AASB 2014-3
Summary
Amendments to Australian Accounting Standards – Accounting for Acquisitions of Interests in
Joint Operations
[AASB 1 & AASB 11]
The amendments require an entity acquiring an interest in a joint operation, in which the activity of
the joint operation constitutes a business, to apply, to the extent of its share, all of the principles in
AASB 3 Business Combinations and other Australian Accounting Standards that do not conflict with
the requirements of AASB 11 Joint Arrangements.
Application Date of the Standard
1 January 2016
Application Date for Group
1 July 2016
Impact on Group Financial report The adoption of this standard in the current financial year has not had a material impact on the
Group and did not impact the Group’s acquisition of the Victorian Gas Assets.
AASB 2014-4
Summary
Clarification of Acceptable Methods of Depreciation and Amortisation
(Amendments to IAS 16 and IAS 38)
The amendments clarify the principle in AASB 116 Property, Plant and Equipment and AASB 138
Intangible Assets that revenue reflects a pattern of economic benefits that are generated from
operating a business (of which the asset is part) rather than the economic benefits that are
consumed through use of the asset. As a result, the ratio of revenue generated to total revenue
expected to be generated cannot be used to depreciate property, plant and equipment and may
only be used in very limited circumstances to amortise intangible assets.
Application Date of the Standard
1 January 2016
Application Date for Group
1 July 2016
Impact on Group Financial report The Group uses diminishing value and units of production bases for the calculation of depreciation
and amortisation. This standard has no impact upon the Group’s methodologies.
71
Notes to the Financial StatementFor the year ended 30 June 2017
2. Summary of significant accounting policies continued
b) Statement of compliance continued
AASB 2015-1
Amendments to Australian Accounting Standards – Annual Improvements to Australian
Accounting Standards 2012–2014 Cycle
Summary
The amendments clarify certain requirements in:
• AASB 5 Non-current Assets Held for Sale and Discontinued Operations – Changes in methods
of disposal
• AASB 7 Financial Instruments: Disclosures - servicing contracts; applicability of the amendments to
AASB 7 to condensed interim financial statements
• AASB 119 Employee Benefits - regional market issue regarding discount rate
• AASB 134 Interim Financial Reporting- disclosure of information ‘elsewhere in the interim
financial report’
Application Date of the Standard
1 January 2016
Application Date for Group
1 July 2016
Impact on Group Financial report The adoption of these updates has not had a material impact on the Group.
AASB 2015-2
Summary
Amendments to Australian Accounting Standards – Disclosure Initiative: Amendments to AASB 101
This Standard amends AASB 101 Presentation of Financial Statements to clarify existing
presentation and disclosure requirements and to ensure entities are able to use judgement when
applying the Standard in determining what information to disclose, where and in what order
information is presented in their financial statements. For example, the amendments make clear
that materiality applies to the whole of financial statements and that the inclusion of immaterial
information can inhibit the usefulness of financial disclosures.
Application Date of the Standard
1 January 2016
Application Date for Group
1 July 2016
Impact on Group Financial report The adoption of these updates has not had a material impact on the Group.
(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 and for which the Group has elected not to early adopt for the annual reporting period ending 30 June 2017, 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 (IFRIC 13 Customer
Loyalty Programmes, AASB 15 Agreements for the Construction of Real Estate, IFRIC 18 Transfers of
Assets from Customers and IFRIC 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 The Group is currently assessing the impact of this standard.
72
Notes to the Financial StatementFor the year ended 30 June 2017 2. Summary of significant accounting policies continued
b) Statement of compliance continued
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 2014-10 applies to annual reporting periods beginning on or after 1 January 2016. Early
adoption permitted.
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 in the current format is not expected to have a material impact on
AASB 16
Summary
the Group.
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 currently assessing the impact of this standard.
73
Notes to the Financial StatementFor the year ended 30 June 2017 2. Summary of significant accounting policies continued
b) Statement of compliance continued
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 is not expected to 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 The adoption of this standard is not expected to have a material impact on the Group.
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.
74
Notes to the Financial StatementFor the year ended 30 June 2017 2. Summary of significant accounting policies continued
b) Statement of compliance continued
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 Group is currently assessing the impact of this standard.
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 is not expected to have a material impact on the Group.
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.
75
Notes to the Financial StatementFor the year ended 30 June 2017 2. Summary of significant accounting policies continued
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 whether other assets or liabilities of the acquirer are assigned to those units.
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
Assets that do not meet the definition of a business are accounted for as asset acquisitions. Under this method, assets are initially
recognised at a value based on their proportionate share of consideration transferred. Under this method transaction costs are capitalised
to the asset and not expensed.
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
• Share of the revenue from the sale of the output by 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.
Other than Sukananti Ltd, which has been disposed of in the year, which had a US dollar functional currency, all other subsidiaries of the
Group have an Australian dollar functional currency.
76
Notes to the Financial StatementFor the year ended 30 June 2017 2. Summary of significant accounting policies continued
g) Investments
Equity instruments at fair value through other comprehensive income
Investments are classified as equity instruments at fair value through other comprehensive income 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.
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
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.
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.
77
Notes to the Financial StatementFor the year ended 30 June 2017 2. Summary of significant accounting policies continued
k) Share based payments continued
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.
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.
78
Notes to the Financial StatementFor the year ended 30 June 2017 2. Summary of significant accounting policies continued
m) Income tax continued
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.
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. The Group has lodged starting base returns
for all exploration and production areas. In June 2013, participants including the Company were granted a combination certificate for
the Cooper Basin projects essentially deeming PEL 92 and PEL 93 to be a single project for PRRT purposes.
o) Exploration and evaluation expenditure
Exploration and evaluation expenditure is accounted for in accordance with the area of interest 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.
79
Notes to the Financial StatementFor the year ended 30 June 2017 2. Summary of significant accounting policies continued
o) Exploration and evaluation expenditure continued
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 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 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 and
then depreciated over the producing life of the asset. 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.
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. The carrying values of property, plant and equipment 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 property, plant and equipment is the higher of fair value less cost to sell and value in use. For an asset that does not generate
largely independent cash flows, recoverable amount is determined for the cash generating unit to which the asset belongs, unless the
asset’s value in use can be estimated to be close to its fair value.
An asset’s or cash generating unit’s carrying amount is written down immediately to its recoverable amount if the asset’s or cash
generating unit’s carrying amount is greater than its estimated recoverable amount.
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.
80
Notes to the Financial StatementFor the year ended 30 June 2017 2. Summary of significant accounting policies continued
s) Impairment of non-current assets
Assets that are subject to amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the
carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset’s carrying amount exceeds
its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs to sell and value in use. 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.
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 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.
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.
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. Oil price options measured at fair
value through other comprehensive income are designated as hedging instruments in cash flow hedges of forecast sales.
Cash flow hedges
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.
The Group uses oil price options as hedges of its exposure to commodity price 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.
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.
81
Notes to the Financial StatementFor the year ended 30 June 2017 2. Summary of significant accounting policies continued
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 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.
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 a commercial property lease. The Group has determined that is does not retain any of the significant risks and
rewards of ownership of this property and has thus classified the lease as an operating lease.
(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.
Factors which could impact the future recoverability include the level of oil and gas reserves, future technological changes which
could impact the cost of extraction, future legal changes (including changes to environmental restoration obligations) and changes to
commodity prices.
82
Notes to the Financial StatementFor the year ended 30 June 2017 2. Summary of significant accounting policies continued
bb) Significant accounting judgements, estimates and assumptions continued
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 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 makes assumptions regarding future production and sales volumes, pricing,
foreign exchange rates and capital and operating expenditure. 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 and pricing.
Provisions for decommissioning and restoration costs
Decommissioning and restoration costs are a normal consequence of oil 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 the year, 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. Included within the segment is also the Orbost Gas Plant which is being sold to APA Group and is classified as assets
held for sale as outlined in Note 11.
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.
83
Notes to the Financial StatementFor the year ended 30 June 2017 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 2017
Revenue
15,513
19,135
Other income and revenue
-
-
Total consolidated revenue
15,513
19,135
Depreciation of property
-
-
-
1,614
1,614
(235)
34,648
1,614
36,262
4,481
39,129
-
1,614
4,481
40,743
(235)
(56)
(291)
(9,557)
(59)
(9,616)
(241)
(2,512)
(43)
-
(1,629)
(533)
(1,226)
58
(2,272)
(9,198)
(1,062)
-
-
-
(241)
(2,512)
(43)
(1,020)
(1,020)
-
-
-
-
-
(1,629)
(533)
(1,226)
58
(2,272)
(1,780)
(10,978)
(672)
(1,734)
-
1,395
1,395
-
(4,031)
(4,031)
(1,577)
(7,035)
(242)
(1,819)
(2,344)
(9,379)
4,665
(7,598)
(13,270)
(13,270)
(360)
(13,630)
Amortisation of
development costs
Amortisation of
exploration costs
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 Loss
Segment liabilities
Segment assets
Non-Current Assets
84
(1,842)
(7,715)
(241)
-
(92)
(2,420)
-
-
-
-
-
-
-
-
(43)
-
(1,629)
(1,226)
58
-
(3,036)
-
-
-
-
-
-
(533)
-
-
(2,272)
-
-
-
3,124
(14,696)
-
-
-
-
-
-
-
(6,162)
(1,062)
-
-
-
(1,577)
4,537
4,537
6,526
16,718
12,684
3,124
(14,696)
(7,035)
(2,344)
(12,312)
163,492
33,825
316,006
159,920
283,981
8,684
203,843
492,644
305,349
3,754
207,597
-
-
492,644
305,349
Notes to the Financial StatementFor the year ended 30 June 2017
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 2016
Revenue
Other income and revenue
20,257
-
Total consolidated revenue
20,257
Depreciation of property
-
Amortisation of
development costs
Amortisation of
exploration costs
Accretion on rehabilitation
provision
Accretion on success
fee liability
(2,461)
(405)
(111)
(1,288)
-
(12)
-
-
-
-
-
-
-
850
850
(284)
-
-
-
-
20,257
850
21,107
7,169
27,426
-
850
7,169
28,276
(284)
(178)
(462)
(2,461)
(1,251)
(3,712)
(405)
(1,399)
(12)
-
-
-
(405)
(1,399)
(12)
Impairment
(4,066)
(17,645)
(154)
(21,865)
(11,820)
(33,685)
Care & maintenance
Share of loss in associate
Fair value adjustment on
success fee
Share based payments
Production expenses
Royalties
Other expenses
Exit provision
Exploration costs
written off
Segment result
Income tax
Net Loss
Segment liabilities
Segment assets
Non-Current Assets
-
-
-
-
(8,181)
(1,133)
-
-
292
4,192
(634)
-
-
-
-
-
-
-
-
-
(87)
19
(1,884)
-
-
(9,068)
-
-
(634)
(87)
19
(1,884)
(8,181)
(1,133)
(9,068)
-
-
-
-
(634)
(87)
19
(1,884)
(3,041)
(11,222)
(1,072)
(2,205)
(2,488)
(11,556)
-
(3,663)
(3,663)
292
(180)
112
(19,579)
(10,608)
(25,995)
(16,524)
(42,519)
7,680
(34,839)
5,280
13,158
10,186
67,984
106,575
106,547
7,212
50,957
1,315
80,473
170,690
118,048
4,308
84,781
5,641
176,331
75
118,123
Revenue from external customers by geographical location of production
Australia
Indonesia
Total revenue
2017
$’000
2016
$’000
34,648
20,257
4,481
7,169
39,129
27,426
Revenue from two customers amounted to $29,423,000 (2016: $19,304,000 from one customer) arising from oil and gas sales.
85
Notes to the Financial StatementFor the year ended 30 June 2017
4. Revenues and expenses
Profit before income tax expense includes the following revenues and expenses whose disclosure is relevant in explaining the
performance of the entity:
Revenues from operations
Oil sales
Gas sales
Total revenue from operations
Other revenue
Interest revenue
Joint venture fees
Total other revenue
Cost of sales
Production expenses
Royalties
Amortisation of exploration costs in areas under production
Amortisation of development costs in areas under production
Total cost of sales
Finance costs
Accretion of rehabilitation cost
Accretion of success fee liability
Total finance costs
Other expenses
Depreciation of property, plant and equipment
General administration (includes employee benefits and lease payments)
Consultants and compliance
Care and maintenance
Loss on fair value of oil price derivative
Loss on deemed disposal of associate
Restoration expense
Fair value adjustment of success fee liability
Realised and unrealised foreign currency translation gain
Total other expenses
Employee benefits expense
Director and employee benefits
Share based payments
Superannuation expense
Total employee benefits expense
Lease payments
Minimum lease payment – operating lease
86
Consolidated
2017
$’000
2016
$’000
15,738
18,910
20,257
-
34,648
20,257
1,331
283
1,614
(9,198)
(1,062)
(241)
777
73
850
(8,181)
(1,133)
(405)
(9,557)
(2,461)
(20,058)
(12,180)
(2,512)
(1,399)
(43)
(12)
(2,555)
(1,411)
(235)
(12,945)
(2,443)
(1,629)
-
-
(1,226)
58
(154)
(284)
(9,319)
(1,462)
(634)
(275)
(105)
-
19
209
(18,574)
(11,851)
(8,172)
(6,668)
(2,272)
(1,884)
(440)
(380)
(10,884)
(8,932)
(352)
(328)
Notes to the Financial StatementFor the year ended 30 June 2017 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
Adjustments in respect of prior year income tax
Income tax benefit
Current royalty tax
Current year
Deferred royalty tax
Origination and reversal of temporary differences
Total royalty tax expense
Numerical reconciliation between tax expense and pre-tax net profit
Accounting loss before tax from continuing operations
Income tax using the domestic corporation tax rate of 30% (2016: 30%)
Increase/(decrease) in income tax expense due to:
Non-deductible expenditure
Adjustments in respect to current income tax of previous years
Recognition of royalty related income tax benefits
Other
Non Australian taxation jurisdictional subsidiaries
Total
Royalty related tax expense
Income tax benefit
Income tax recognised in other comprehensive income
Fair value movement on derivative financial instruments
Income tax using the domestic corporation tax rate of 30% (2016: 30%)
Consolidated
2017
$’000
2016
$’000
(38)
(38)
4,824
-
4,824
4,786
(6,117)
(6,117)
(1,481)
(1,481)
(7,598)
205
205
7,543
159
7,702
7,907
-
-
-
-
-
(7,035)
(25,995)
2,111
7,799
(54)
(38)
2,279
488
-
4,786
(7,598)
(2,812)
(232)
364
-
-
(24)
108
-
7,907
(369)
(369)
300
300
87
Notes to the Financial StatementFor the year ended 30 June 2017
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 2017, 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 (2016 $nil).
Franking Tax Credits
At 30 June 2017 the parent entity had franking tax credits of $42,856,152 (2016: $42,856,152). The fully franked dividend equivalent is
$142,852,840 (2016 $99,997,690).
PRRT
Cooper Energy Limited has recognised a Deferred Tax Liability for Petroleum Resource Rent Tax (PRRT) of $1,481,000 (2016: $nil)
relating to PRRT on the Company’s producing gas assets. The Company has not recognised a Deferred Tax Asset for PRRT of
$29,386,000 (2016: $26,623,000) relating to 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.
Income Tax Losses
(a) Revenue Losses
Cooper Energy has recognised a Deferred Tax Asset for the year ended 30 June 2017 of $16,275,000 (2016: $7,661,000).
(b) Capital Losses
Cooper Energy has not recognised a Deferred Tax Asset for Australian income tax capital losses of $62,272,095 (2016: $60,108,000) on
the basis that it is not probable that the carried forward capital losses will be utilised against future assessable capital profits.
88
Notes to the Financial StatementFor the year ended 30 June 2017 5. Income tax continued
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
Provisions
Other
Unrealised currency translation gain
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 in equity
Tax losses
Consolidated
Statement of
Financial Position
Consolidated Statement
of Comprehensive
Income
2017
$’000
2016
$’000
2017
$’000
2016
$’000
2,419
325
933
-
1,486
325
641
-
15,934
17,588
3,398
(5,882)
-
24
38
-
-
-
-
-
38
18,740
18,521
-
-
-
1,199
365
2,488
473
2,255
10
(10)
1,762
(1,762)
2
-
575
5,640
496
199
(2)
1,199
(210)
1,900
5,640
(22)
-
320
-
16,275
7,661
8,614
6,984
23,054
16,345
(158)
144
(2)
466
2
(29)
(106)
Deferred tax income (expense)
14,954
8,207
Deferred tax asset/(liability) from corporate tax
4,315
(2,176)
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
As represented on the Consolidated Statement of Financial Position,
deferred tax asset
1,481
4,315
-
-
As represented on the Consolidated Statement of Financial Position,
net deferred tax liability
-
2,176
-
-
-
-
-
-
89
Notes to the Financial StatementFor the year ended 30 June 2017 6. 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 2017 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 current
period these potential ordinary shares are considered antidilutive as their conversion to ordinary shares would reduce the loss per share.
Accordingly, they have been excluded from the dilutive earnings per share calculation.
The following reflects the income and share data used in the basic and diluted earnings per share computations:
Net loss attributable to ordinary equity holders of the parent from continuing operations
(9,847)
(18,088)
Consolidated
2017
$’000
2016
$’000
Weighted average number of ordinary shares for basic earnings per share
Weighted average number of ordinary shares adjusted for the effect of dilution
Basic earnings per share for the period (cents per share)
Diluted earnings per share for the period (cents per share)
Net 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 dilution
Basic earnings per share for the period (cents per share)
Diluted earnings per share for the period (cents per share)
2017
Thousands
2016
Thousands
683,255
343,602
683,255
343,602
(1.4)
(1.4)
(5.3)
(5.3)
Consolidated
2017
$’000
2016
$’000
(12,312)
(34,839)
2017
Thousands
2016
Thousands
683,255
343,602
683,255
343,602
(1.8)
(1.8)
(10.1)
(10.1)
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.
The weighted average number of potentially dilutive shares at 30 June 2017 is 705,291 thousand shares (including performance rights
and share appreciation rights that have not been achieved and vested at the end of the financial year).
90
Notes to the Financial StatementFor the year ended 30 June 2017 7. 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
2017
$’000
49,425
98,000
147,425
2016
$’000
16,815
32,902
49,717
41
91
(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. At June 2017 there are no term deposits with a maturity greater than 3 months. At June 2016 this
amount also included term deposits of $10 million which had a maturity greater than 3 months, but which were not subject to
significant break costs had the Company wished to withdraw these funds before maturity.
(ii) The carrying value of term deposits approximates their fair value.
As disclosed in Note 30, the Company has executed binding underwritten commitments for $250 million under a senior reserve based
lending facility. Financial close and drawdown are subject to the Company being in a position to fund the agreed non debt proportion of
the Sole gas field development costs, completion of the APA transaction, and a number of conditions precedent, including perfection
of security, environmental and insurance due diligence and a gas market independent review report.
91
Notes to the Financial StatementFor the year ended 30 June 2017 7. Cash and cash equivalents and term deposits continued
Reconciliation of net profit after tax to net cash flows from operating activities
Net Profit/(loss) for the Year
Adjustments for:
Consolidated
2017
$’000
2016
$’000
(12,312)
(34,839)
Amortisation of development costs in areas of production
9,616
3,712
Amortisation of exploration costs in areas under production
Depreciation of property, plant and equipment
Exploration and evaluation written off
Exit provision
Impairment of Non-Current Assets
(Gain)/loss on sale of assets held for sale
Share of loss in associate
Share based payments
Finance cost
Restoration expense
Fair value adjustment of success fee liability
Unrealised foreign currency translation (gain)/loss
Loss on fair value movement of oil price derivatives
(Increase)/decrease in trade and other receivables
(Increase)/decrease in inventories
(Increase)/decrease in prepayments
(Decrease)/increase in deferred taxes
(Decrease)/increase in trade and other payables
(Decrease)/increase in current tax liability
(Decrease)/increase in provisions
(Increase)/decrease in held for sale assets
Net cash from operating activities
8. Trade and other receivables
Current Assets
Trade receivables (i)
Accrued revenue
Related party receivables (ii)
Related party receivables – joint ventures (iii)
Hedge settlement receivable
Interest receivable
92
241
291
1,819
(3,703)
1,020
(1,395)
533
2,272
2,555
1,226
(58)
57
-
405
462
(112)
3,663
33,685
904
87
1,884
1,411
-
(19)
138
275
(10,474)
3,513
-
(507)
940
337
(5,010)
(8,844)
13,216
-
559
4,132
4,078
(922)
859
4,539
(4,143)
7,935
Consolidated
2017
$’000
2,813
7,855
-
-
-
210
2016
$’000
2
2,954
170
77
125
72
10,878
3,400
Notes to the Financial StatementFor the year ended 30 June 2017 8. Trade and other receivables continued
(i) Trade receivables are non-interest bearing and are generally on 30-90 days terms. There are no past due or impaired
receivables and none that have a history of past default.
(ii) All related party receivables are current within agreed terms of trade and do not exceed 180 days.
(iii) Related party receivables for joint ventures are for work to be undertaken in the near term and are within
contractual arrangements.
Non-Current Assets
Trade receivables
Consideration receivable
9. Prepayments
Current Assets
Bank facility fee
Insurance
Other
Non-Current Assets
Insurance
10. Equity instruments at fair value through other comprehensive income
Shares at fair value
A reconciliation of the movement during the year is as follows:-
Opening balance
Fair value movement
Closing balance
The equity investments consist of one investment and the Group has received no dividends throughout the financial year.
Consolidated
2017
$’000
1,739
1,258
2,997
2016
$’000
-
-
-
Consolidated
2017
$’000
79
1,787
36
1,902
911
911
2017
$’000
658
790
(132)
658
2016
$’000
154
142
7
303
-
-
2016
$’000
790
1,343
(553)
790
93
Notes to the Financial StatementFor the year ended 30 June 2017 11. Discontinued operations and assets held for sale
Indonesia
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. Total consideration was $5.7 million consisting of cash
consideration, shares in BAS, deferred consideration and working capital adjustments. The transaction completed on the 28 February
2017. A receivable of $2.3 million has been recognised relating to the deferred consideration receivable from Bass Oil Company Limited
which will be fully received by December 2018.
Tunisia
The Company exited the Hammamet and Nabeul joint ventures during the 2016 financial year. The remaining interest in Tunisia, the
Bargou joint venture, has been assigned to joint venture partner Dragon Oil Ltd (Dragon).
The abandonment activities and finalisation of transfer of operatorship were completed during the March 2017 quarter, and the closure of
the Tunisia office.
Orbost Gas Plant
On 1 June 2017 the Company announced the execution of the Agreement (originally announced on 27 February 2017) for APA Group
to acquire, upgrade and operate the Orbost Gas Plant. Completion of this transaction remains subject to certain conditions precedent
including finalisation of the Company’s debt funding and final investment decision for the Sole gas development project. The assets and
liabilities relating to the plant are classified as held for sale.
The losses from discontinued operations are presented on a separate line in the Consolidated Statement of Comprehensive Income.
Trade and other receivables
Oil and gas assets
Other assets
Total assets held for sale
Trade and other payables
Provisions
Other liabilities
Total (liabilities) associated with assets held for sale
Net (liabilities)/assets directly associated with disposal Group
Revenue for the year from discontinued operations
Expenses for the year from discontinued operations
Gain on sale
Impairment loss recognised
Pre-tax loss for the year from discontinued operations
Income tax expense
Loss for the year from discontinued operations
Operating cash flows from discontinued operations
Investing cash flows from discontinued operations
Financing cash flows from discontinued operations
Total net cash flow from discontinued operations
Basis loss per share from discontinued operations (cents per share)
Diluted loss per share from discontinued operations (cents per share)
94
2017
$’000
-
24,631
459
2016
$’000
3,861
819
108
25,090
4,788
(14,790)
(10,658)
-
(25,448)
(358)
4,481
(282)
(221)
(142)
(645)
4,143
7,169
(7,200)
(11,873)
1,395
-
(1,020)
(11,820)
(2,344)
(16,524)
(121)
(227)
(2,465)
(16,751)
420
(929)
-
1,164
(3,055)
-
(509)
(1,891)
(0.4)
(0.4)
(4.9)
(4.9)
Notes to the Financial StatementFor the year ended 30 June 2017 12. Investments in associate
The Group has a 15.78% (2016: 13.94%) interest in Bass Oil Limited (ASX: BAS), which is involved in oil production and development in
Indonesia oil and gas exploration in the Gippsland Basin, offshore Victoria, Australia. The Group’s interest in Bass Oil Limited is accounted
for using the equity method in the consolidated financial statements. During the 2015 financial year, the Group obtained significant
influence over the investment following the election of one of the Group’s board members to the board of Bass Oil Limited, and therefore
commenced accounting for the investment as an investment in associate.
The carrying value of the Group’s investment in its associated is nil following the recognition of the Group’s share of the associated profit
and loss. The fair value of the investment at 30 June 2017 is $353,361.
The Group has accumulated unrecognised losses in respect of the Group’s investment in its associate. Any future profits generated by
the associate will be offset by the accumulated unrecognised losses before any profit can be recognised.
13. Asset acquisition
On 24 October 2016 the Company entered into a binding agreement to acquire the Victorian gas assets of Santos Limited (Victorian
Gas Assets). The assets acquired include:
• a 50% interest and operatorship of the producing Casino Henry gas assets (VIC/L30, VIC/L24) (“Casino Henry”) in the offshore
Otway Basin;
• a 10% interest in the producing Minerva gas field (VIC/L22) and Minerva Gas Plant in the Otway Basin (“Minerva”);
• the remaining 50% interests in the Sole gas field (“Sole”) and Orbost Gas Plant in the Gippsland Basin, increasing Cooper Energy’s
interest in both assets to 100%;
• acreage prospective for gas in the offshore Otway Basin, Victoria, including VIC/P44, VIC/RL11 and /RL12; and
• a 100% interest in the largely depleted and non-operating Patricia Baleen gas field and associated infrastructure (“Patricia Baleen”)
in the offshore Gippsland Basin. Sub-sea infrastructure at Patricia Baleen connects the adjacent Longtom gas field to the Orbost
Gas Plant.
The acquisition of Casino Henry, Sole, Patricia Baleen field and the prospective acreage in the Otway Basin completed on 10 January
2017. The acquisition of the Minerva gas field and Minerva Gas Plant completed on 7 April 2017.
Consideration transferred:
Cash (including working capital)
Contingent consideration1
$’000
65,000
20,000
85,000
(1) In accordance with the binding agreements entered into to acquire the Victorian Gas Assets, a further $20 million milestone payment
is payable on the earlier of:
• achievement of the final investment decision for the Sole gas project, due within 60 days of a formal sanctioning of Sole by the
Board of Cooper Energy; or
• the receipt of cash consideration for any sell-down by Cooper Energy of an interest in any of the Victorian Gas Assets. The amount
payable to Santos shall not exceed the proceeds received by Cooper Energy and any such payment will be made within 10 days
after Cooper Energy actually receives the proceeds for the sell-down.
The bonus consideration has been provided for at 30 June 2017 within trade and other payables (refer to Note 18)
The table below illustrates the assets acquired and liabilities assumed as part of the transactions.
Inventory
Property, plant and equipment
Exploration and evaluation assets
Oil and gas assets
Rehabilitation provision
Other provision
Net assets acquired
Casino Henry, Sole,
Patricia Baleen
$’000
2,459
436
84,061
64,724
Minerva
Total
$’000
$’000
-
3,307
-
1,966
2,459
3,743
84,061
66,690
(66,620)
(5,067)
(71,687)
(266)
-
(266)
84,794
206
85,000
95
Notes to the Financial StatementFor the year ended 30 June 2017
Transferred Exploration
and Evaluation
Development
Total
$’000
$’000
$’000
1,373
-
-
4,012
6,530
5,385
6,530
66,690
66,690
(241)
(8,962)
(9,203)
1,132
68,270
69,402
5,174
100,354
105,528
(4,042)
(32,084)
(36,126)
1,132
68,270
69,402
1,778
10,143
11,921
-
-
(405)
1,373
(4,297)
(4,297)
627
627
(2,461)
(2,866)
4,012
5,385
5,174
27,134
32,308
(3,801)
(23,122)
(26,923)
1,373
4,012
5,385
14. Oil and Gas assets
Year end 30 June 2017
Carrying amount at 1 July 2016
Additions
Gas assets acquired (i)
Amortisation
Carrying amount at 30 June 2017
As at 30 June 2017
Cost
Accumulated amortisation & impairment
Year end 30 June 2016
Carrying amount at 1 July 2015
Classified as held for sale
Additions
Amortisation
Carrying amount at 30 June 2016
As at 30 June 2016
Cost
Accumulated amortisation & impairment
(i) Refer to Note 13.
96
Notes to the Financial StatementFor the year ended 30 June 2017 15. Impairment
Impairment
Investments in associates
Exploration and evaluation
Total
Consolidated
2017
$’000
2016
$’000
-
-
-
(154)
(21,711)
(21,865)
There were no impairment losses for continuing operations recognised during the financial year.
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. No
impairment indicators were present and no impairment was recognised on exploration and evaluation assets during the first half of the
2017 financial year. During the 2016 financial year impairment losses were recognised in respect of the Company’s Victorian Otway Basin
permits and the Cooper Basin Northern licences.
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, no impairment indicators were present and no impairment was recognised on oil and gas assets during the 2017
financial year.
16. Property, plant and equipment
Year end 30 June
Carrying amount at 1 July
Assets acquired
Additions
Disposals/written off
Depreciation and amortisation
Transferred to assets held for sale
Carrying amount at 30 June
As at 30 June
Cost
Accumulated depreciation
Consolidated
2017
$’000
2016
$’000
708
3,743
2,159
(1)
(830)
(2,085)
3,694
981
-
45
(34)
(284)
-
708
5,917
2,101
(2,223)
(1,393)
3,694
708
97
Notes to the Financial StatementFor the year ended 30 June 2017
17. 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
Exploration expenditure classified as held for sale
Additions
Exploration acquired (i)
Unsuccessful exploration wells written (off)/back (ii)
Impairment
Carrying amount at 30 June (iii)
(i) Refer to Note 13
Consolidated
2017
$’000
2016
$’000
110,976
105,363
-
(15,270)
29,094
84,061
22,878
19,424
(800)
292
-
(21,711)
223,331
110,976
(ii) Exploration write offs relate to exploration wells that were plugged and abandoned as unsuccessful during the year.
(iii) Recoverability is dependent on the successful development and commercial exploration or sale of the respective areas of interest.
18. Trade and other payables
Trade payables (i)
Hedge payable
Contingent bonus consideration (ii)
Accruals
Related party payables – joint arrangements (iii)
Consolidated
2017
$’000
5,110
22
20,000
29,366
54,498
4,022
58,520
2016
$’000
489
-
-
2,505
2,994
5,020
8,014
(i) Trade and other payables are non-interest bearing and are normally settled on 30-90 day terms.
(ii) Contingent bonus consideration is payable to Santos Ltd on final investment decision on the Sole gas project. Refer to Note 13.
(iii) Related party payables are accrued expenditure incurred on joint arrangements.
98
Notes to the Financial StatementFor the year ended 30 June 2017 19. Provisions
Current Liabilities
Restoration provision
Exit penalty provision
Employee provisions
Non-Current Liabilities
Long service leave provision
Restoration provisions
Movement in carrying amount of the non-current restoration provision:
Carrying amount at 1 July
Transferred to held for sale
Restoration expenditure incurred
Transferred to current provisions
Provision through asset acquisition
Increase through accretion
Impact of changes in restoration assumptions (i)
Carrying amount at 30 June
Consolidated
2017
$’000
14,584
3,754
850
19,188
2016
$’000
-
3,663
401
4,064
365
346
99,437
65,202
99,802
65,548
65,202
45,049
(9,980)
(155)
(14,584)
-
-
-
71,687
19,424
2,512
(15,245)
1,399
(670)
99,437
65,202
(i) Changes in restoration assumptions results from a change in discount rate from 2.12% to 2.41% and changes in gross
cost assumptions.
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 at the relevant time 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 provision as at 30 June 2017 equalled 2.41% (2016: 2.12%) reflecting the Australian
Government 10 year bond rate.
99
Notes to the Financial StatementFor the year ended 30 June 2017 20. Financial liabilities
Success fee financial liability
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
Consolidated
2017
$’000
3,044
2016
$’000
3,059
3,059
3,066
43
(58)
12
(19)
3,044
3,059
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/RL13, 14 & 15 assets in the Gippsland Basin offshore Victoria acquired on 7 May 2014.
The discount rate used in the calculation of the liability as at 30 June 2017 equalled 2.41% (2016: 2.12%) reflecting the Australian
Government 10 year bond rate.
21. Contributed equity and reserves
Share capital
Ordinary shares
Issued and fully paid
Capital raising
During the period the Group raised $203.9 million (net of costs and tax of $9.9 million) through
institutional placements and entitlement offers, 699,662,038 new ordinary shares were issued.
Fully paid ordinary shares carry one vote per share and carry the right to dividends.
Consolidated
2017
$’000
2016
$’000
343,161
137,558
Movement in ordinary shares on issue
At 1 July
Equity issue
2017
2016
Thousands
$’000
Thousands
$’000
435,186
137,558
331,905
115,460
699,662
203,940
101,047
21,650
Issuance of shares to contractors
630
223
-
Issuance of shares for performance rights & share appreciation rights
5,073
1,440
2,234
-
448
At 30 June
1,140,551
343,161
435,186
137,558
100
Notes to the Financial StatementFor the year ended 30 June 2017 21. Contributed equity and reserves continued
Reserves
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
Consolidated
At 1 July 2015
Other comprehensive
income/(expenditure)
Transferred to
issued capital
Share-based payments
(541)
-
-
-
895
237
-
-
At 30 June 2016
(541)
1,132
-
(448)
1,884
7,208
Other comprehensive
income/(expenditure)
Transferred to issued
capital
Share-based payments
-
-
-
At 30 June 2017
(541)
Nature and purpose of reserves
Consolidation reserve
(1,132)
-
-
-
-
(1,440)
2,049
7,817
5,772
25
-
-
6,151
(700)
(553)
(1,016)
-
-
-
-
-
25
(700)
-
-
-
861
-
-
-
-
(553)
(132)
-
-
(448)
1,884
6,571
(403)
(1,440)
2,049
6,777
25
161
(685)
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.
Accumulated Losses
Movement in accumulated losses:
Balance at 1July
Net loss for the year
Balance at 30 June
Consolidated
2017
$’000
2016
$’000
(52,579)
(17,740)
(12,312)
(34,839)
(64,891)
(52,579)
101
Notes to the Financial StatementFor the year ended 30 June 2017
21. Contributed equity and reserves continued
Capital Management
For the purpose of the Group’s capital management, capital includes issued capital and all other equity reserves attributable to the equity
holders of the parent. 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’s capital management, amongst other things, aims to ensure that it meets
financial covenants attached to its finance facilities that form part of its capital structure requirements. The Group currently has no interest
bearing debt. 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 2017 and
30 June 2016.
22. Financial risk management objectives and policies
The Group’s principal financial instruments comprise cash and short term deposits, receivables, equity investments and payables.
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.
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.
Fair value hierarchy
All financial instruments for which fair value is recognised or disclosed are categorised within the fair value hierarchy, described as follows,
and based on the lowest level input that is significant to the fair value measurement as a whole:
Level 1 – Quoted market prices in an active market (that are unadjusted) for identical assets or liabilities
Level 2 – Valuation techniques (for which the lowest level input that is significant to the fair value measurement is directly or
indirectly observable)
Level 3 – Valuation techniques (for which the lowest level input that is significant to the fair value measurement is unobservable)
For financial instruments that are recognised at fair value on a recurring basis, the Group determines whether transfers have occurred
between Levels in the hierarchy by re-assessing categorisation (based on the lowest level input that is significant to the fair value
measurement as a whole) at the end of each reporting period.
102
Notes to the Financial StatementFor the year ended 30 June 2017 22. Financial risk management objectives and policies continued
Set out below is an overview of financial instruments held by the Group, with a comparison of the carrying amounts and fair values as at
30 June 2017:
Consolidated
Financial assets
Equity instruments at fair value through other
comprehensive income
Financial liabilities
Success fee financial liability
Derivative financial instruments
Carrying amount
Fair value
Level
2017
$’000
2016
$’000
2017
$’000
2016
$’000
1
3
2
658
790
658
790
3,044
114
3,059
1,275
3,044
114
3,059
1,275
The financial assets and liabilities of the Group are recognised in the consolidated statement of financial position in accordance with the
accounting policies set out in Note 2.
The following summarises the significant methods and assumptions used in estimating the fair values of financial instruments:
Equity instruments 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.
Derivative financial instruments
The derivative financial instruments relate to the Group’s hedging activities to hedge against cash flow risks from movements in oil price,
for which hedge accounting has been applied. The fair value of the derivative financial instruments are obtained from third party valuation
reports and are valued using the Black-Scholes model.
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/RL13-15 assets acquired on 7 May 2014. The significant unobservable valuation inputs
for the success fee financial liability include: a probability of 37% that no payment is made and a probability of 63% the payment is made
in 2022. The discount rate used in the calculation of the liability as at 30 June 2017 equalled 2.41% (June 2016: 2.12%). The financial
liability is valued using a discounted cash flow model and the value is sensitive to changes in discount rate and probability of payment.
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 2017 and 30 June 2016.
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 2017 and 30 June 2016
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.
During the year, the Group operated internationally and was exposed to foreign exchange risk arising from various currency exposures,
to the United States 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.
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.
103
Notes to the Financial StatementFor the year ended 30 June 2017
22. Financial risk management objectives and policies continued
The financial instruments which are denominated in US dollars are as follows:
Financial assets
Cash
Term deposits at bank
Trade and other receivables (current and non-current)
Financial liabilities
Trade and other payables
Consolidated
2017
$’000
2016
$’000
2,680
7,045
-
75
4,011
4,016
-
282
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
2017
$’000
(608)
743
2016
$’000
(987)
1,206
The Group uses oil price options to manage some of its transaction exposures. These options are 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.
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 2017 of
$4,011,293 (2016: $2,953,605).
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
Impact on after tax profit
2017
$’000
461
(461)
2016
$’000
339
(339)
The Group has no borrowings at 30 June 2017 (2016: $ nil) nor has the Group drawn and repaid any loans from a financial institution
during the reporting period.
The Group has interest bearing deposits of $98,000,000 (2016: $32,902,000).
If the interest rate were 1% rate higher at the balance date
If the interest rate were 1% rate lower at the balance date
104
Impact on after tax profit
2017
$’000
314
(314)
2016
$’000
24
(24)
Notes to the Financial StatementFor the year ended 30 June 2017 22. Financial risk management objectives and policies continued
Credit risk
Credit risk arises from the financial assets of the Group which comprise cash and cash equivalents and trade and other receivables
including hedge settlement receivables. 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 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.
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.
Trade and other payables amounting to $58,520,000 (2016: $8,014,000) are payable within normal terms of 30 to 90 days.
Financial liability amounting to $5,000,000 (undiscounted) will be payable upon the commencement of commercial production of
hydrocarbons on the Group’s VIC/RL13-15 assets. The timing of this payment is uncertain but not expected to be within one year.
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.
Share price risk
Share price risk arises from the movement of share prices on a prescribed stock exchange. The Group has equity instruments measured
at fair value through other comprehensive income the fair value of which fluctuates as a result of movement in the share price.
If the share price were 10% higher at the balance date
If the share price were 10% lower at the balance date
23. Hedge accounting
Impact on revaluation reserve
2017
$’000
66
(66)
2016
$’000
79
(79)
The Company uses Australian dollar Brent options to manage some of its transaction exposures. The options are designated as cash flow
hedges and are entered into for a period consistent with the oil price exposure of the underlying transactions. Historically this was typically
over a 12 to 18 month period.
Cash flow hedges
Australian dollar oil price options measured at fair value through other comprehensive income are designated as hedging instruments in
cash flow hedges of forecast sales in US dollars. These forecast transactions are highly probable, and they comprise about 28% of the
Company’s total expected oil sales in US dollars to December 2017.
Oil price cash flow hedges outstanding at 30 June 2017:
• A$54.45 50% participating swaps for 5,000 bbl/month for the period January 2017 to December 2017.
The table below shows the Company’s hedges that are currently outstanding.
Hedge arrangements (bbl remaining)
A$54.45 – 50% participating swap
FY18H1
30,000
Total
30,000
These transactions have been entered into in order to reduce the variability of cash flows arising from oil sales during the period July 2017
to December 2017. The impact of these transactions is that the Company has locked in an average floor price of $54.45/bbl over 28% of
production while still being able to participate in upside should the oil price increase.
105
Notes to the Financial StatementFor the year ended 30 June 2017 23. Hedge accounting continued
The fair value of the options vary based on the level of sales and changes in forward rates.
30 June 2017
30 June 2016
Assets
$’000
Liabilities
$’000
Assets
$’000
Liabilities
$’000
Fair value of oil price options
-
114
-
1,275
The terms of the oil price options match the terms of the expected highly probable forecast sales with the exception of currency given the
instruments are Australian dollar denominated options and the forecast sales being in US dollars.
During the financial year, $0.5 million was reclassified from other comprehensive income (OCI) to the income statement in respect of
realised hedge settlements.
The cash flow hedges of the expected future sales were assessed to be highly effective and a net unrealised loss of $0.2 million and a tax
expense of $48,000 relating to the hedging instrument are included in OCI.
The amounts retained in OCI at 30 June 2017 are expected to mature and impact the statement of profit or loss in the first half of 2018.
24. 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 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
2017
$’000
2016
$’000
255
-
-
255
14,600
30
-
322
248
-
570
5,405
2,200
-
14,630
7,605
(i) The joint venture has applied for a revision to the work schedule that is currently with the minister for approval.
Cooper Energy has executed a number of material contracts to the value of $208.0 million at 30 June 2017 relating to the Sole gas
project. The minimum payment under these contracts at 30 June 2017 is $67,421,000.
As at 30 June 2017 the Parent entity has bank guarantees for $160,512 (2016: $161,512). These guarantees are in relation to
performance bonds on exploration permits and guarantees on office leases.
On 1 July 2017 Cooper Energy entered into an operating lease over its Perth office. The operating lease is for a period of 36 months.
A bank guarantee for $60,000 was also issued in respect of the office lease.
106
Notes to the Financial StatementFor the year ended 30 June 2017 25. 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, Tunisia and Indonesia. The Group has the following interests in joint arrangements in
the following major areas:
a) Joint Arrangements in which Cooper Energy Limited is the operator/manager
Australia
VIC/RL 13-15
Indonesia
Oil and gas exploration and production
100%1
100%
Ownership Interest
2017
2016
Tangai-Sukananti KSO
Oil and gas exploration and production
Tunisia
Bargou Exploration Permit
Oil and gas exploration
b) Joint Arrangements in which Cooper Energy Limited is not the operator/manager
Australia
PEL 90K
PEL 93*
PEL 100
Oil and gas exploration
Oil and gas exploration and production
-2
-3
25%
30%
55%
30%
25%
30%
Oil and gas exploration
19.165%
19.165%
PRL 183-190 (Formerly PEL 110)
Oil and gas exploration
PEL 494
PEP 150
PEP 168
PEP 171
PRL 32
Oil and gas exploration
Oil and gas exploration
Oil and gas exploration
Oil and gas exploration
Oil and gas exploration
PRL 85-104* (Formerly PEL 92)
Oil and gas exploration and production
*Includes associated PPL’s
1. Abandonment costs are shared between Cooper Energy Limited and former JV partners.
2. Sold during the period.
3. Withdrawn from during the period.
20%
30%
20%
50%
25%
30%
25%
20%
30%
20%
50%
25%
30%
25%
It is noted that the Victorian gas assets acquired do not meet the definition of joint arrangements and as such are not included in this note.
107
Notes to the Financial StatementFor the year ended 30 June 2017 26. Related parties
The Group has a related party relationship with its subsidiaries, its joint arrangements (see Note 25) 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)
Mr J. Schneider
Ms A. Williams
Executive Directors
Mr D. Maxwell
Mr H. Gordon (executive director to 24 June 2017)
Executives at year end
Mr D. Clegg (General Manager Development from 1 May 2017)
Ms A. Evans (Legal Counsel and Company Secretary)
Mr E. Glavas (General Manager Commercial and Business Development)
Mr I. MacDougall (General Manager Operations)
Ms V. Suttell (Chief Financial Officer, acting from 18 January 2017 and Chief Financial Officer from 1 July 2017)
Mr A. Thomas (General Manager Exploration & Subsurface)
Key Management Personnel who resigned during the year
Mr J. de Ross (Chief Financial Officer and Company Secretary to 9 December 2016)
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
Consolidated
2017
$
2016
$
4,355,038
3,550,762
94,811
20,158
183,275
163,750
1,395,760
1,361,363
283,371
-
6,312,255
5,096,033
108
Notes to the Financial StatementFor the year ended 30 June 2017
26. Related parties continued
Subsidiaries
The Group financial statements include the financial statements of Cooper Energy Limited and the subsidiaries listed in the following table.
Country of
incorporation
British Virgin Islands
British Virgin Islands
Equity interest
2017
%
-1
100%
2016
%
100%
100%
British Virgin Islands
100%
100%
British Virgin Islands
100%
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
Australia
100%
100%
100%
100%
100%
-
-
-
-
-
-
-
-
-
-
-
-2
-2
100%
100%
100%3
100%4
100%5
100%4
100%6
100%4
100%4
100%7
100%8
100%5
100%9
100%
100%
Name
Cooper Energy Sukananti Limited
CE Tunisia Bargou Ltd
CE Hammamet Ltd
CE Nabeul Ltd
Cooper Energy (Seruway) Pty Ltd
CE Poland Pty 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
1 Sold during the period.
2 Deregistered during the period.
3 Incorporated on 19 July 2016.
4 Incorporated on 14 October 2016.
5 Incorporated on 22 May 2017.
6 Incorporated on 21July 2016.
7 Incorporated on 25 July 2016.
8 Incorporated on 27 July 2016.
9 Incorporated on 29 July 2016.
Joint arrangements
During the reporting period, the Group provided geological and technical services to joint arrangements it manages at a cost of
$1,454,000 (2016: $1,746,000). At the end of the financial period, nothing was outstanding for these services (2016: $77,800).
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.
109
Notes to the Financial StatementFor the year ended 30 June 2017
27. Share based payment plans
There are two share based payment plans in place at 30 June 2017. 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 in December 2016 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
Average share
price at
commencement
date of grant
Average
contractual life
of rights at grant
date in years
Remaining life of
rights in years
15 December 2015
22,278,100
21 December 2016
9,841,875
7,892,812
3,810,503
$0.175
$0.298
3
3
2
3
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
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
110
Number of Rights
2017
7,892,812
2016
-
3,810,503
7,892,812
(233,975)
-
(475,042)
-
-
-
10,994,298
7,892,812
-
-
Number of Rights
2017
22,278,100
2016
-
9,841,875
22,278,100
(660,415)
-
(1,340,844)
-
-
-
30,118,716
22,278,100
-
-
Notes to the Financial StatementFor the year ended 30 June 2017
27. Share based payment plans continued
The fair value of services received in return for the performance rights granted are measured by reference to the fair value of performance
rights granted. The estimate of the fair value of the services received is measured based on the Black-Scholes methodology to produce
a Monte-Carlo simulation model that allows for the incorporation of market based performance hurdles that must be met before the shares
vest to the holder.
Share Appreciation Rights Fair value assumptions
15 December 2015
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
6.2 cents
17.5 cents
1.95%
50%
0%
15 December 2015
13.1 cents
16.5 cents
2.13%
53%
0%
Share Appreciation Rights Fair value assumptions
21 December 2016
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
11.5 cents
29.78 cents
1.575%
56%
0%
21 December 2016
29.78 cents
34.5 cents
1.88%
56%
0%
2011 Employee Performance Rights Plan
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.
111
Notes to the Financial StatementFor the year ended 30 June 2017 27. Share based payment plans continued
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.
Information with respect to the number of performance rights granted to employees is as follows:
Date Granted
Number of
rights granted
Average share price
at commencement
date of grant
Average contractual
life of rights at
grant date in years
Remaining life of
rights in years
1 December 2014
6,584,708
$0.285
3
1
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
2017
Number of rights
2016
11,167,070
17,276,975
-
-
(4,535,319)
(2,234,300)
(886,918)
(2,920,525)
(444,637)
(955,080)
5,300,196
11,167,070
2,650,106
3,017,074
The weighted average price of shares vested during the financial year was $0.36 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.
Fair value assumptions
Fair value at measurement date
Share price
Risk free interest rate
Expected volatility
Dividend yield
112
1 December 2014
19.4 cents
28.5 cents
2.35%
51%
0%
Notes to the Financial StatementFor the year ended 30 June 2017
28. 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
217,259
172,914
Consolidated
2017
$
2016
$
Taxation and other services
Amounts received or due and receivable by related practices of Ernst & Young Australia for:
Auditing and review of financial reports of an entity in the consolidated Group
29. 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
Loss of the parent entity
Total comprehensive income/(loss) of the parent entity
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
65,000
18,540
282,259
191,454
-
-
282,259
191,454
2017
$’000
2016
$’000
155,552
52,613
436,960
202,061
61,308
9,633
111,539
80,400
343,161
137,558
(33,980)
(21,878)
25
161
(685)
25
(700)
(553)
7,818
7,209
316,500
121,661
(13,415)
(12,759)
729
(1,253)
255
-
-
255
322
245
-
567
113
Notes to the Financial StatementFor the year ended 30 June 2017 30. Events after the reporting period
Transfer of Operatorship
On 1 July 2017 operatorship of the Sole gas project, the Orbost Gas Plant and the Patricia Baleen field transferred from Santos Ltd to
Cooper Energy.
On 1 August 2017 operatorship of the Casino Henry gas assets (including VIC/L30, VIC/L24, VIC/P44, VIC/RL11 and VIC/RL12) transferred
from Santos Ltd to Cooper Energy. Employees and contractors were transferred to Cooer Energy as part of the operatorship transfers.
Management Changes
Virginia Suttell was appointed Chief Financial Officer effective 1 July 2017. Ms Suttell had been Chief Financial Officer, Acting since
18 January 2017.
Michael Jacobsen was appointed General Manager Projects effective 1 July 2017. Mr Jacobsen had previously been leading the
Sole development project team for Santos Ltd and his employment transferred at the same time operatorship of the Sole assets were
transferred to Cooper Energy.
Both Ms Suttell and Mr Jacobsen are part of the Management Team and are KMP.
Sole Final Investment Decision and Funding
Subsequent to 30 June 2017, the Company made a Final Investment Decision for the Sole gas project as a result of significant
advancements towards achieving full funding of the Sole gas project as outlined below.
On 29 August 2017, the Company announced a fully underwritten accelerated non renounceable 2 for 5 entitlement offer to raise
approximately $135 million, subject to standard market terms. As a result, 456,220,522 new ordinary shares in the Company will be
issued. The offer will close on 19 September 2017. The offer price is $0.295.
On 29 August 2017, Cooper Energy Limited executed binding underwritten commitments for $250 million under a senior reserve based
lending facility, to be used for the purposes of debt funding a proportion of the Sole gas field development costs. Financial close and
drawdown are subject to the Company being in a position to fund the agreed non debt proportion of the Sole gas field development costs,
completion of the APA transaction, and a number of conditions precedent, including perfection of security, environmental and insurance
due diligence and a gas market independent review report.
114
Notes to the Financial StatementFor the year ended 30 June 2017 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 2017 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 2017.
Signed in accordance with a resolution of the Directors.
Mr John C. Conde AO
Chairman
29 August 2017
Mr David P. Maxwell
Managing Director
115
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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 2017, the consolidated statement of comprehensive income, the consolidated statement of
changes in equity and the 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
2017 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 APES110 Code of Ethics for Professional
Accountants (the Code) that are relevant to our audit of the financial report in Australia; and we have
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.
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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 statements. 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.
1. Funding, liquidity and basis of preparation
Why significant
How our audit addressed the key audit matter
The Group is entering a capital intensive phase
of its Sole gas project. As outlined in note 24 to
the financial report, the Group has capital
commitments of $208.0 million at 30 June 2017
($104.0 million due in less than 12 months). At
30 June 2017, the Group has cash and cash
equivalents of $147.4 million as outlined in note
7 to the financial report.
Immediately prior to signing our audit opinion, we
evaluated the Group’s funding position and its ability
to repay its debts as and when they fall due for at
least 12 months from the date of our opinion. In
obtaining sufficient audit evidence, we:
• understood the process undertaken by the Group
to determine the appropriateness of the use of
the going concern basis;
As outlined in note 30 to the financial report,
subsequent to 30 June 2017, the Group has
taken steps to secure additional sources of
funding, being:
• A fully underwritten equity issue for
approximately $135 million, subject to
standard market terms; and
• A senior reserves based lending facility for
$250 million which is fully underwritten,
subject to a number of conditions precedent,
as outlined in note 2 a) to the financial
report.
If the Group is not able to satisfy the various
conditions precedent to secure the reserve
based lending facility, or secure alternate
sources of financing, the Group has the ability to
defer discretionary expenditure or take alternate
steps to moderate the cash outflows of the
business.
This is a key audit matter given there is
judgement required by the Group in determining
the cash flow forecasts, the value and timing of
capital commitments and financing cash inflows,
and the forecast expenditure committed for the
development of the Sole gas project.
• understood the capital commitments of the
Group;
•
•
•
assessed the base cash flow forecasts and
options that the Group has to defer or otherwise
not incur certain expenditure, and performed
sensitivity analysis to understand the impact of
variances to the planned budget and forecast on
the Group’s ability to pays its debts;
assessed the status of the $135 million
underwritten equity issue;
assessed the nature and status of the senior
reserve based lending facility including the
remaining conditions precedent;
• obtained representation from management and
the Board with regards to current and future
capital commitments; and
•
assessed the adequacy of the related disclosures
in the financial report.
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2. Acquisition of gas assets
Why significant
How our audit addressed the key audit matter
As disclosed in note 13 of the Group’s financial
report, the Group acquired the Victorian Gas
Assets during the year, for cash consideration of
$65 million and deferred consideration of $20
million.
Accounting for the acquisition required judgment
due to the structure of the transaction and the
assets acquired and liabilities assumed being
material to the Group’s financial performance
and position at 30 June 2017.
We assessed the treatment of the transaction in
accordance with Australian Accounting Standards. In
obtaining sufficient audit evidence, we assessed:
•
•
•
the Sale and Purchase Agreements and
associated agreements;
the consideration paid and contingent
consideration payable; and
the allocation of the purchase based on the
relative fair values performed by the Group,
including the identification of all assets acquired
and liabilities assumed.
We assessed the adequacy of the Group’s disclosures
in respect of this transaction as set out in note 13.
3. 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 judgment and the use of
assumptions by the Group, as outlined in note 2
(ii) of the Group’s financial report. These
estimates can have a material impact on the
financial report, primarily in the following areas:
•
•
•
•
capitalisation and classification of
expenditure as exploration and evaluation
(E&E) assets or oil and gas assets;
valuation of assets and impairment testing;
calculation of depreciation, depletion and
amortisation (DD&A); and
estimation of the costs and timing of
decommissioning and restoration activities.
Further details on these areas are set out in
notes 2, 4, 14, 15, 17 and 19 to the Group’s
financial report.
Our audit procedures focused on the work of the
Group’s experts with respect to the hydrocarbon
reserve estimations, in accordance with Australian
Auditing Standards.
In obtaining sufficient audit evidence, we:
•
assessed the competence and objectivity of
internal management experts involved in the
estimation process;
• understood the Group’s reserves estimation
process and controls;
•
•
assessed and tested the design and operating
effectiveness of relevant controls over the
reserves review process employed by the Group;
reconciled to application financial information;
and
• understood 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.
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4. Impairment assessment of exploration and evaluation assets
Why significant
How our audit addressed the key audit matter
The carrying value of E&E assets is subjective as
it is based on the Groups ability, and intention, to
continue to explore and evaluate the assets. The
carrying value is also impacted by the results of
exploration and evaluation work. This creates a
risk that the amounts stated in the Group’s
financial report may not be recoverable.
The impairment testing process is complex and
judgmental, and for E&E assets commences with
an assessment against indicators of impairment
under Australian Accounting Standard - AASB 6
Exploration for and Evaluation of Mineral
Resources. This is to reflect that E&E assets may
be at an early stage in the project life cycle.
Key assumptions, judgments and estimates used
in the formulation of the Group’s impairment
assessment of E&E assets are set out in note 15
to the financial report.
We assessed the impairment analysis prepared by
the Directors, evaluating the assumptions and
methodologies used by the Group and the estimates
made. In obtaining sufficient audit evidence, we:
• considered the Group’s right to explore in the
relevant exploration area which included
obtaining and assessing supporting
documentation such as license agreements and
correspondence with relevant government
agencies;
• considered the Group’s intention to carry out
substantive E&E activity in the relevant
exploration area, or plans to move the asset into
development. This included assessment of the
Group’s cash-flow forecast models approved by
the Board for evidence of planned future activity,
and enquiries with senior management and
Directors as to the intentions and strategy of the
Group;
• assessed the carrying value of E&E assets where
recent exploration activity in a given exploration
license provided negative indicators as to the
recoverability of amounts capitalised;
• considered the Group’s assessment of the
commercial viability of results relating to E&E
activities carried out in the relevant license area;
• assessed the Group’s ability to finance both
planned future E&E activity and asset
development plans;
• assessed the capabilities of management’s
internal experts for the purposes of estimating
the potential resources associated with those E&E
assets, as outlined in key audit matter 3; and
• considered the adequacy of the financial report
disclosures regarding impairment and the
recoverable amount of the Group’s E&E assets.
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5. Decommissioning and restoration provisions
Why significant
How our audit addressed the key audit matter
The Group has recognised decommissioning and
restoration provisions of $114 million at 30
June 2017 which are disclosed in note 19 to the
Group’s financial report.
Our audit procedures focused on the work of the
Group’s experts.
In obtaining sufficient audit evidence, we:
The calculation of decommissioning and
restoration provisions requires significant
judgment in respect of asset lives, timing of
restoration work being undertaken,
environmental legislative requirements, the
extent of restoration activities required and
future costs.
•
•
assessed the competence and objectivity of both
the Group’s internal and external experts
involved in the estimation process;
assessed the independence of the Group’s
external experts;
• evaluated the adequacy of the expert’s work;
• understood the Group’s decommissioning and
restoration estimation processes;
•
•
•
tested the consistency in the application of
principles and assumptions to other areas of the
audit such as reserves estimation and
impairment testing;
tested the mathematical accuracy of the net
present value calculations and discount rate
applied; and
reconciled the calculations to the financial
report.
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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 Group’s 30 June 2017 Annual Report other than the financial report and
our auditor’s report thereon. We obtained the Directors’ Report and the Overall Financial Review that
are to be included in the Annual Report, prior to the date of this auditor’s report, and we expect to
obtain the remaining sections of the Annual Report after the date of this auditor’s report.
Our opinion on the financial report does not cover the other information and we do not and will not
express any form of assurance conclusion thereon.
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.
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121
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 entity’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 in
the preparation of the financial report. We also conclude, based on the audit evidence obtained,
whether a material uncertainty exists related to events and conditions that may cast significant
doubt on the entity’s ability to continue as a going concern. If we conclude that a material
uncertainty exists, we are required to draw attention in the auditor’s report to the disclosures in
the financial report about the material uncertainty or, if such disclosures are inadequate, to
modify the opinion on the financial report. However, future events or conditions may cause an
entity 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.
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Report on the Remuneration Report
Opinion on the Remuneration Report
We have audited the Remuneration Report included in pages 46 to 62 of the Directors’ Report for the
year ended 30 June 2017.
In our opinion, the Remuneration Report of Cooper Energy Limited for the year ended 30 June 2017,
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
29 August 2017
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124
Securities Exchange and Shareholder Information
as at 31 August 2017
Listing
The company’s shares are quoted on the Australian Securities Exchange under the code of “COE”.
Number of Shareholders
There were 6,207 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 2017)
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 Rights
Number of Holders of Rights
22
10
Number of holders
Number of Shares
% of issued capital
940
1,617
1,012
2,149
489
238,048
4,724,197
8,060,432
73,268,666
1,054,259,964
6,207
1,140,551,307
0.02
0.41
0.71
6.42
92.43
100.00
Total Rights
16,625,088 Performance Rights
30,118,716 Share Appreciation Rights
Unmarketable Parcels
There were 1,277 members, representing 698,819 shares, holding less than a marketable parcel of 1,667 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.
J P Morgan Nominees Australia Limited
HSBC Custody Nominees (Australia) Limited
Beach Energy Limited
Citicorp Nominees Pty Limited
National Nominees Limited
BNP Paribas Nominees Pty Ltd
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