51Talk Online Education Group Annual Report 2016

FY2016 Annual Report · 51Talk Online Education Group

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2016 Annual Report

Cooper Energy Limited
ABN 93 096 170 295

Front cover: Orbost Gas Plant, East Gippsland, Victoria, Australia. Cooper Energy holds a 50% interest in the plant which is connected to the
Eastern Gas Pipeline and positioned to be a hub for onshore processing of gas from offshore Gippsland Basin gas fields, including the company’s
Sole and Manta fields. Minor modifications are proposed to the plant as part of the Sole Gas Project, which is currently being prepared for final
investment decision. Inside and back cover: Process flow diagrams for the Orbost Gas Plant.

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 2016 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 2016 Annual General Meeting of Cooper
Energy Limited ABN 93 096 170 295
(Company) will be held at 10.30 am (ACDT)
on Thursday, 10 November 2016 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

Cooper Energy reports its reserves and
resources according to the SPE (Society of
Petroleum Engineers) Petroleum Resources
Management System guidelines (PRMS).

Reserves are those quantities of petroleum
anticipated to be commercially recoverable
by application of development projects
to known accumulations from a given date
forward under defined conditions.

Contingent resources are those quantities
of petroleum estimated, as of a given date,
to be potentially recoverable from known
accumulations but the applied project(s)
are not yet considered mature enough for
commercial development due to one or
more contingencies.

In PRMS, the range of uncertainty is
characterised by three specific scenarios
reflecting low, best and high case
outcomes from the project. The terminology
is different depending on which class is
appropriate for the project, but the
underlying principle is the same regardless
of the level of maturity. In summary, if the
project satisfies all the criteria for Reserves,
the low, best and high estimates are
designated as proved (1P), proved plus
probable (2P) and proved plus probable
plus possible (3P), respectively. The
equivalent terms for contingent resources
are 1C, 2C and 3C.

Rounding

Numbers in this report have been rounded.
As a result, some figures may differ
insignificantly due to rounding and totals
reported may differ insignificantly from
arithmetic addition of the rounded numbers.

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 “2016”,
FY16 or “2016 financial year” refer to the
12 months ended 30 June 2016 unless
otherwise stated. References to “2015”,
FY15 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

JOA: Joint Operating Agreement

km: kilometres

LNG: liquified natural gas

LTI: loss time injury

m: metres

SCF: standard cubic feet

PJ: petajoules

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

MMbbl: million barrels of oil

MMboe: million barrels of oil equivalent

SCF: standard cubic feet

TRCFR: total recordable case frequency rate

Our business is finding, developing
and commercialising oil and gas.

We do this with care and strive to
provide attractive returns for our
shareholders and good commercial
outcomes for our customers.

Key features:

• cash generating oil production from the western flank of the Cooper Basin

• gas resources that are well positioned, and being prepared for, supply to

eastern Australian customers

• a management team and board with proven success in exploration, gas

commercialisation and building resource companies.

Key figures:

For the year ended 30 June 2016

Production:

465,000 barrels of oil

Average production cost:

A$29.71 per barrel

Net (debt)/cash and investments:

$50.8 million

2P Reserves:

3.0 million barrels of oil

2C Contingent Resources*:

64.3 million boe

Shares on issue:

435.2 million

* Contingent resources reported above supersede that reported to the ASX on 15 August 2016

(including the Operating and Financial Review of that date which is included in this report) due to
revisions to reflect 100% ownership of the BMG gas and liquids resource and downward revisions to
Tunisian contingent resources following confirmation of withdrawal from the Hammamet permit.

The year in brief

Key themes

Operating soundly and with care in a low oil price environment eonment

• Direct operating cash cost of A$29.71/bbl, average price A$60.75/bbl

• General and administration costs reduced 9%

• Drilling curtailed to preserve cash

• 963,000 hours worked with zero lost time injuries or recordable cases

• 380 hours worked for charitable causes under Cooper Energy’s Making

a Difference program

Gas projects moving forward

• Heads of Agreement secured for foundation gas sales from Sole Gas Project

• Front End Engineering & Design of Sole Gas Project

• Upgrades to Contingent and Prospective Resources for Sole and Manta

Concentration of our portfolio consistent with strategy

• Sale of Indonesian exploration assets

• Divestment process for Indonesian production assets

• Staged withdrawal from Tunisia

3.08

3.00

2.16

2.01

1.88

0.52

0.49

0.59

0.48

0.46

2012

2013

2014

2015

2016

2012

2013

2014

2015

2016

Proved & probable (2P) reserves
million barrels of oil at 30 June

Production
million barrels

Key results

Financial

Safety: lost time injuries
and recordable cases
rate per million hours worked

• Revenue of $27.4 million, down from $39.1 million on lower oil prices

• Significant non-operating items of $(32.0)million

• Statutory net loss after tax of $34.8 million compared with FY15

loss after tax of $63.5 million

• Underlying net loss after tax of $2.8 million, compared with

FY15 underlying loss after tax of $1.3 million

• Cash flow from operating activities of $7.9 million, up from $2.0 million

• Cash and investments of $50.8 million, up from $41.3 million

4.50

4.00

3.50

3.00

2.50

2.00

1.50

1.00

0.50

0.00

Operations: Production, reserves, resources and exploration

• Zero recordable incidents. Zero lost time injuries

• Production of 465,000 barrels of oil, down from 475,000 barrels

• 1 well drilled; the successful Bunian-4

• Proved and probable (2P) reserves of 3.0 million barrels, down from

3.1 million barrels

2013

2014

2015

2016

LTI

TRCFR

Proved & Probable Reserves (2P)
MMbbl as at 30 June 2016

• Contingent resources (2C) of 64.3 million boe

1.73

1.27

Portfolio management and corporate development

• Indonesian exploration assets sold for proceeds of $12 million

• Retention lease secured for BMG gas and liquids resource,

Australia

Indonesia

Gippsland Basin

$112.13

$124.08

$85.48

123

166

93.6

$60.75

2013

2014

2015

2016

Market capitalisation and oil price
as at 30 June

Market capitalisation
$million

Oil price A$/bbl

Contingent Resources (2C)
MMboe as at 30 June 2016

11.3

7.6

0.4

Australia oil

Australia gas

Indonesia gas

Tunisian oil and gas

45.0

Chairman’s Report
John Conde AO

The work completed is germane to
your company’s future activities and
returns; addressing critical questions
such as when and how the company
will generate revenue from gas,
agreed prices and pricing formulae
for its gas, the customers involved,
the investments required, safety and
environmental requirements and the
most suitable financing structures,
costs and obligations.

The coming months are expected to
see an acceleration of activity as this
information is incorporated into a final
investment proposal for the first phase
of our Gippsland Basin gas projects,
the Sole gas field, for decision by your
board. Commitment to the project
will represent the most significant
decision by the company since it
elected to focus its initial efforts on
the western flank of the Cooper Basin.

Given this significance, it is
noteworthy that the projections
underpinning the company’s gas
strategy are, as the Managing Director
notes in his report, proving accurate
with respect to the gas prices and
flows in south eastern Australia.

Gas supply in the region is becoming
increasingly tight and the company’s
initiative has given it ‘early-mover
advantage’ in securing resources and
having gas to market at a time when
gas available for sale has appreciating
value. Your board is resolved
shareholders get the best leverage
from the position the company has
secured whilst being prudent in
managing risk.

While the gas strategy has occupied
much of the year’s efforts and
planning, the company retained
focus on day-to-day performance
and improvement.

The 2016 financial results, a
statutory loss of $34.8 million and
an underlying loss of $2.8 million,
reflect the impact of low oil prices on
asset values and revenue generation.

Behind these results, the company
increased cash generation, reduced
costs and excelled in safety
management.

The improvement in safety is
particularly pleasing as the company’s
management and staff recorded
a year free of lost time injuries and
recordable incidents.

Shareholders may recall my
comments in the previous report
noting that the company had
increased its investment in the
management and reporting of safety.
Results suggest the investment has
been effective, although safety tools
and systems are ultimately only as
effective as the diligence applied by
the people involved, and I commend
staff for their efforts in this respect.

Balance sheet strength has been
a longstanding feature of Cooper
Energy. The decision to conduct an
institutional placement and share
purchase plan during 2016 has
enabled the company to conclude the
year with increased cash resources
and a stronger position as it prepares
for financing the Sole Gas Project.
The success of the placement
was assisted by participation from
a number of new institutional
shareholders, and I would like to
record our appreciation of all who
participated.

The work of the previous four years
has brought Cooper Energy to the
‘cross-roads’ in its strategy; that point
where it departs from operations
no longer required and makes the
commitment to the ventures on
which it will build its future.

Indonesia has been a success
story for the company in terms of
the reserves and production that
have been added. Further uplift in
production is considered possible
through the implementation of a
development plan to remove
capacity constraints.

This is the fourth
annual report since
I joined the board
of your company.
The theme of the
preceding three
reports has been
the company’s efforts
to implement its
strategy; moving to
a focus on Australia
and in particular
its plans for a gas
business supplying
south eastern
Australia.

I am pleased to note that, while
the previous three reports outlined
plans and progress, this year we
report outcomes and milestones
completed.

The tasks completed during the year
are fast giving a commercial reality
to the company’s plans to develop
its Gippsland Basin gas resources.
Heads of Agreement for gas sales
were secured. Detailed project design
and construction schedules were
finalised. Project costing was itemised
and determined.

However, the company is resolved
that capital be concentrated on
the cash and growth generating
opportunities within the ambit of its
Australian focussed strategy.

Accordingly, divestment of the
Indonesian production assets is
ongoing and this, combined with
the staged withdrawal from Tunisia,
is expected to focus the portfolio
entirely on Australia. Achievement of
this would be the first time in twelve
years that Cooper Energy’s portfolio
consists solely of Australian assets.

Formal financial commitment to the
Sole Gas Project, anticipated this
calendar year, will set the company
on the path of developing and

delivering the new venture forecast
to multiply production and reserves
several times current levels.

Your board believes the company
is ready for this commitment,
capable of delivery and that it is
reasonable to expect the work done
will be reflected by a significant
improvement in shareholder value
as the project matures.

On behalf of all shareholders, I would
like to thank my fellow directors
and all employees for their service
and contribution to the company.

John Conde AO
Chairman

Oil tanks, Callawonga, Cooper Basin

Managing Director’s Report
David Maxwell

resources considered the most
competitive supply for south
eastern Australia.

Onshore, we secured acreage,
and conducted exploration, in the
Otway Basin which identified deep
conventional gas-bearing reservoirs.
Offshore, we acquired interests
in undeveloped resources in the
Gippsland Basin, the largest and
most competitive source of gas
supply to south eastern Australia as
well as in the strategically located
Orbost Gas Plant.

The past year has seen the company
take the first phase of its Gippsland
gas projects, the Sole Gas Project, to
the verge of an investment decision.

An affirmative Final Investment
Decision for Sole represents a
company-changing event through
its impact on reserves, capital
management and expenditure.
It will set in motion the investment
expected to generate a five-fold
lift in production and complete the
reorientation from oil producer and
explorer to an energy company
generating the large majority of its
income from stable, long term gas
contracts. We are planning to make
this decision in the December quarter.

Market developments have continued
to unfold consistent with our
expectations, with the tightening
of gas supply created by additional
demand from Queensland LNG
production, and a range of other
factors, already evident in south
eastern Australian gas pricing.

The average Victorian wholesale
gas price for the months of June
and July 2016 was, respectively,
125% and 145% higher than their
previous year comparative. Volatility
has increased, with the wholesale
price ranging between $5.40/GJ
and $44.85/GJ in this period.
The anticipated tightening of gas
supply for south eastern Australia
is now forecast to emerge earlier,

and be more significant, than
previously expected. In this context,
the Sole Gas Project is well placed
and well timed.

Your company is now positioned to
develop a new greenfield offshore gas
project to supply eastern Australia at
a time when gas supply to this market
has never been more valuable.

Care

Cooper Energy has two key
requirements for all of its activities
and plans: that they deliver
acceptable shareholder return 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 for our operations is
provided on page 21 of this report.

I am pleased to report that your
company completed the year
with zero recordable safety and
environmental incidents and zero lost
time injuries. This result has been
achieved against the backdrop
of uncertainty and cost challenges
faced by the industry generally.

A zero injury – zero incident
performance is, of course, the
minimum level of safety management
that should be acceptable. It is,
nonetheless, a commendable
improvement on the previous year
which featured one lost time injury
and a number of recordable incidents.

The improvement has been recorded
following the investment in continual
improvement systems and culture
foreshadowed in last year’s annual
report and through the day-in and
day-out diligence by management
and staff to a safe workplace.

We are mindful that maintaining a
zero injury – zero incident standard
will require safe operations, every
day, in every workplace, by every
employee and contractor.

As an annual report,
this document is
necessarily focussed
on the results and
position for the
12 months to 30 June.

These results show
year-on-year progress
and improvement
in most aspects of
your company not
exposed to oil prices.
Safety performance,
cash balances and
costs all recorded
outcomes superior to
the preceding year.

However, our plans for value
creation extend beyond the short
term. We are now five years into
our plan to transform the company
through building a gas business
to supply opportunities foreseen
emerging in eastern Australia
from 2017.

The first four years of strategy
implementation saw your company
dedicate itself to acquiring a deep
understanding of the Australian
domestic gas market and identifying,
then securing, the acreage and

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 28.

In broad terms, the financial results
reflect the impact of lower oil prices on
operating results and of impairments
to discontinued operations and
exploration and evaluation assets.
The four key features of the financial
performance were:

1) A statutory loss after tax of

$34.8 million, recorded after
significant items of $(32.0) million,
which largely relate to assets
sold in Indonesia or those subject
to sales or withdrawal processes
in Indonesia and Tunisia.
In comparison, the company
recorded a statutory loss of
$63.5 million in the previous year.

2) An underlying or operating loss

(ie exclusive of significant items)
of $2.8 million, which compares
with the previous year’s underlying
loss of $1.3 million after tax.
The movement compared with
the previous year is attributable
to the oil prices in 2016 which
were, on average, 30% lower than
the previous year. It is noteworthy
that the company’s oil operations
were profitable at the underlying
level, with the underlying loss
being incurred as a result of the
additional expenditure made in
building its gas business.

As discussed below, the company
mitigated the impact of the lower
oil price through a combination
of hedging and cost management
measures.

3) Cash generation of $7.9 million

from operating activities. Cooper
Energy’s production assets are low
cost, and were cash-generating at
the low prices experienced during
the year, with a direct operating
cost of A$29.71/bbl.

4) A stronger balance sheet, with cash
and investments of $50.8 million,
23% higher than at the beginning
of the year. The improvement can
be attributed to the company’s
successful capital raising during
the year, which raised net proceeds
of $21.2 million. The company is
appreciative and mindful of the
support shown by shareholders
and new investors in enabling this
outcome. Financial assets are
supplemented by a reserves based
lending facility of up to $40 million
available, as outlined in note 7 of
the financial report.

Costs and cash management

The decline in oil prices that began
in the previous year gained new
momentum in early 2016, presenting
the oil and gas industry with its most
challenging business conditions for
several years. Your company has
managed the impact of the downturn
through a combination of measures
designed to protect cash and to reset
expenditure, whilst still maintaining
the resources necessary to progress
our transformational growth projects.

Zero-cost hedging was implemented
to mitigate the downside in oil prices
without punitive costs. Hedge gains
delivered revenue of $2.5 million
during the year.

Capital expenditure was curtailed,
with the exception of the Gippsland
Basin gas projects, which accounted
for 70% of the year’s total incurred
capital expenditure of $31.6 million.
Capital expenditure in other regions
for 2016 was $9.4 million, 53% lower
than the previous year’s comparative.
While this rationing of capital has
impacted Cooper Basin production
levels, it has meant the company has
been able to concentrate its cash
resources on its most significant near
term growth opportunity and retain
balance sheet strength.

General and administration cash costs
were reduced by 9% compared with

the previous year, an outcome
for which the personal contribution
of all employees and directors is
acknowledged. Reduced head count
and a company-wide effort to identify
and deliver cost savings contributed
to a lower expenditure run rate.
Employees, directors and contractors
contributed personally, through
initiatives such as reduced working
hours by staff and the decision by
management and directors to offer
a 10% reduction to their salary.

Portfolio management

Portfolio management is an ongoing
discipline to ensure the company is
favourably exposed, and directing
its resources, to those opportunities
expected to provide the best risk-
weighted return to shareholders.

2016 saw a step change in the
company’s portfolio management
consistent with the maturation of its
strategy. Recent years have seen the
company engaged in the acquisition
of acreage and assets to execute
its gas strategy. With the foundation
assets having been secured at Sole,
Basker, Manta Gummy (BMG) and
Orbost, the emphasis of our portfolio
management in 2016 shifted to
rationalisation for better focus on our
growth opportunities.

This has meant withdrawal from
Indonesia, with the exploration assets
having been divested and a sale
process for the production assets
ongoing.

Withdrawal from Tunisia is expected
to be completed in the current year
with the fulfilment of the amended
work program and term expiry for the
Bargou joint venture, the company’s
only remaining permit in the country.

The expected completion of
withdrawal from Tunisia and Indonesia
will mark another milestone in
the company’s strategy execution
as its portfolio will, as intended, be
concentrated entirely on Australia.

Managing Director’s Report
David Maxwell

In doing so, the company has exited
higher risk international exploration
plays in Poland, Romania, Tunisia and
Indonesia over the past 4 years and
concentrated its efforts on lower
risk oil and gas assets advantageously
placed for low cost production and
access to market and which can offer
satisfactory returns for shareholders.

These criteria will be applied in our
ongoing portfolio management
efforts, with a focus on gas and oil
assets with a foreseeable pathway
to commercialisation within the
medium term.

Reserves, exploration and
development

A review of operations and report
on reserves and resources by the
Executive Director – Exploration
and Production, Hector Gordon
commences on page 10. Proved
and Probable reserves as at 30 June
were 3.0 million boe. Of this figure,
1.3 million boe are located in the
Cooper Basin of Australia with
the balance being the subject of the
Indonesian divestment initiative.

There are three aspects of the
company’s technical work during the
year I want to highlight.

1) Drilling activity levels

The curtailment of capital expenditure
outside the Gippsland Basin meant
that field exploration and development
activity was low. For the first year
in its history, the company did not
participate in any drilling in Australia.
The company participated in a single
well for the year, the successful
Bunian-4 appraisal/development well
in Indonesia.

The suspension of in-field drilling
activities has reduced available
production in the near term, but
capital has been preserved and
technical analysis maintained. The
company is ready for the resumption
of drilling in the Cooper Basin in
FY17 with a number of exploration,
appraisal and development targets.

2) Cooper Basin oil reserves

and potential

While the company did not conduct
drilling in the Cooper Basin during the
year, technical analysis was sustained
with the results including the addition
of reserves and identification of
potential for further exploration.

For some time, oil production from
a number of producing wells
in the Cooper Basin has exceeded
expectations, suggesting the presence
of greater reserves than previously
assessed.

Exploration studies including seismic
reprocessing, depth analysis and
remapping led to upgrades for original
oil in place and/or reserves potential.
The resultant 0.2 million barrel
upgrade to the company’s share of
Cooper Basin proved and probable oil
reserves was sufficient to offset most
of the 0.3 million barrel depletion
from production during the year, and
year-end 2P reserves were 92% of
the opening balance.

3) Increased gas resources, the
potential for reserves uplift
and exploration

The Gippsland Basin gas fields were
the principal focus of technical work
during the year. Analysis conducted
resulted in upwards revisions to
contingent resources estimates for the
Sole and Manta fields.

The company’s contingent resources
(2C) of gas in its Gippsland Basin gas
projects are assessed to be 262 PJ, of
which 121 PJ relates to the Sole gas
field. An affirmative final investment
decision (FID) for the Sole project
will establish the economic viability
of the field and the inclusion of these
resources as proved and probable
reserves equivalent to 20 million boe,
roughly fifteen times the company’s
current Australian reserves.

In addition, the potential for the
existence of sizeable additional
Gippsland Basin gas accumulations
has been identified in proven

hydrocarbon-bearing structures in
the Manta gas field and adjacent
Chimaera prospect. The analysis has,
as discussed on page 15, resulted in
a substantial uplift to the prospective
resources assessed for the licence
which have added a new dimension
to the appraisal and possible
development of the Manta gas field.

Gippsland Basin gas projects

The company’s gas strategy
entails the development of its gas
resources in the Gippsland Basin
offshore Victoria for sale into long
and short term supply opportunities
from 2019 onwards. Our plans for
these resources feature a two-
phase development: the first phase
being the Sole Gas Project, with
commercialisation of the less mature
Manta field being the second phase.

Sole Gas Project

The Sole gas field is the subject
of a fully costed development
proposal that is in the final stages of
preparation for submission for FID.
Cooper Energy has a 50% interest
in Sole and Santos Ltd holds the
remaining 50% and is the Operator.

Front End Engineering and Design
of the project was finalised
subsequent to year end, defining
a project with an estimated capital
cost of $552 million.

Sales of gas from Sole could
commence from January 2019,
subject to an affirmative FID.

The company has secured foundation
sales agreements for the project,
having contracted a total of 7.6 PJ
pa from its 12.5 PJ pa equity share
of Sole output through Heads of
Agreement with AGL Limited and
O-I Australia. It is intended that
the balance of the company’s gas
will either be contracted at the
appropriate time or reserved for
spot sales with a view to maximising
shareholder value.

A detailed financing plan to support
FID has been prepared with the
assistance of external advisors.
The quantum and quality of the
project’s cash flows are such that the
majority of the company’s share of
development costs are expected
to be funded through debt funding.

The balance of the funding
requirement, including determination
of the most appropriate equity
levels, will be determined prior to
FID according to the optimisation of
shareholder return and project risk.

Manta gas and liquids field

In July 2015 the company announced
that a sound business opportunity
had been identified for the
commercialisation of the Manta gas
field. The field, which is assessed to
contain contingent resources (2C) of
106 PJ of gas and 2.6 million barrels
of liquids, is located in proximity
to the Sole gas field and Orbost
Gas Plant that affords significant
valuable synergies from coordinated
development and operation.

Manta is considered a longer dated
supply option with conceptual plans
being for production of approximately
24 PJ pa of gas with associated
liquids from 2021.

The prospect of supply from Manta
has already attracted interest from
gas buyers, including AGL Limited
who has an option entitlement of up
to 4 PJ pa from the field.

The rigorous process of defining and
costing the Sole project has been
instructive for potential development
costs for the Manta project, indicating
the potential for considerable savings
against the estimates envisaged in the
business case.

Cooper Energy is Operator and
has a 100% interest in the VIC/RL13,
VIC/RL14 and VIC/RL15 permits
which include the Basker, Manta and
Gummy gas and liquids resources.
Commercialisation of Manta will
require the drilling of an appraisal well.

It is expected that commitment to the
Sole project development will provide
a catalyst for the introduction of
a new partner for the Manta project.

Concluding comments

In many ways, the 2017 financial
year marks the point when the various
strategy elements pursued over the
previous four years converge, and the
company emerges with a distinctly
different form and outlook.

Fulfilment of the plans I have outlined
in this report, including an affirmative
final investment decision for the Sole
Gas Project, will see Cooper Energy
in the coming months:

- with an acreage portfolio consisting

entirely of Australian assets;

- change from an exposure biased to

gas rather than oil;

- with substantially increased proved

and probable reserves; and
- with significant changes to its

balance sheet as funding and capital
is managed to support the funding
of the Sole project.

In particular, an affirmative decision
to develop Sole will initiate a two
year project construction period to
realise substantial long term revenue
flows and establish Cooper Energy as
one of the very few Australian listed
companies offering exposure to the
south eastern Australian gas market.

The company is resolved to deliver
this long term vision, and that it be
delivered in a form which offers due
rewards for its shareholders and with
the necessary care.

We are mindful of the need for
excellence in near term performance.
The reduced Cooper Basin drilling
activity in 2016 and natural decline
means that our production from this
region is expected to be significantly
lower at 240,000 barrels to 280,000
barrels of oil in 2017.

This trend in production is regarded
as transitionary prior to the
development of the Gippsland Basin
gas projects. Nevertheless, cash
and costs will be managed tightly
for alignment with current revenue
whilst maintaining the expenditure
necessary for efficient delivery of our
growth projects and the technical
contribution that has underwritten
our successes in the Gippsland,
Otway and Cooper basins.

I look forward to reporting further
on our progress over the course of
the year.

David Maxwell
Managing Director

Reserves & Resources

Reserves
Cooper Energy’s 2P reserves at 30 June 2016 are assessed to be 3.00 million barrels of oil (MMbbl). This is a decrease
of 0.08 MMbbl from 30 June 2015. The key factors in the revision are reserves upgrades from subsurface studies in the
PEL 92 Joint Venture producing fields in the Cooper Basin, success at the Bunian-4 development well in the
Tangai-Sukananti KSO, Indonesia and production of 0.46 million barrels of oil.

Petroleum Reserves at 30 June 2016 (MMbbl)

Category

Developed

Undeveloped

Total 1

Proved
(1P)

Proved & Probable
(2P)

Proved, Probable &
Possible (3P)

Australia

Indonesia

0.62

0.16

0.78

0.50

0.31

0.82

Total

1.12

0.48

1.59

Australia

Indonesia

0.98

0.29

1.27

0.93

0.80

1.73

Total

1.91

1.09

3.00

Australia

Indonesia

1.70

0.48

2.18

1.39

1.70

3.09

Total

3.08

2.19

5.27

1. 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.

Year-on-year movement in Petroleum Reserves (MMbbl)

Category

Reserves at 30 June 2015

FY16 Production

Revisions1

Reserves at 30 June 2016 2

Proved
(1P)

1.97

(0.46)

0.08

1.59

Proved & Probable
(2P)

Proved, Probable &
Possible (3P)

3.08

(0.46)

0.38

3.00

4.82

(0.46)

0.91

5.27

1. The reserves revisions include Cooper Energy’s share of future crude fuel usage in the Cooper Basin. The estimated fuel usage for the Cooper Basin

opearations are: 1P 0.03 MMbbl, 2P 0.05 MMbbl and 3P 0.09 MMbbl. There is no produced crude oil used for fuel in Indonesia.

2. Totals may not reflect arithmetic addition due to rounding.

Contingent Resources
Cooper Energy’s 2C contingent resources at 30 June 2016 have increased by 5.9 million barrels of oil equivalent
(MMboe) to an estimate of 64.3 MMboe. The key revisions are an upgrade of resources in the Sole Field in
the Gippsland Basin, offshore Victoria, as announced to the ASX on 26 November 2015 and the divestment of the
Indonesian exploration permits.

Contingent Resources at 30 June 2016 1

Category

Gas
PJ

Australia 2

184.8

Indonesia

Tunisia 2

Total 1

1.2

1.6

187.7

Oil
MMbbl

4.0

0.0

3.5

7.4

Total
MMboe

35.8

0.2

3.8

Gas
PJ

261.9

2.3

5.6

39.7

269.7

Oil
MMbbl

7.6

0.0

10.4

17.9

Total
MMboe

52.6

0.4

11.3

64.3

Gas
PJ

385.2

4.3

18.5

408.0

Oil
MMbbl

12.1

0.0

29.9

42.1

Total
MMboe

78.5

0.7

33.1

112.4

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. Contingent resources reported above supersede that reported to the ASX on 15 August 2016 (including the Operating and Financial Review of that date
which is included in this report) due to revisions to reflect 100% ownership of the BMG gas and liquids resource and downward revisions to Tunisian
contingent resources following confirmation of withdrawal from the Hammamet permit.

Year-on-year movement in 2C Contingent Resources (MMboe)

Category

Australia

Indonesia

Resource at 30 June 2015

Revisions 2

Resource at 30 June 20161, 2

38.8

13.8

52.6

2.6

(2.2)

0.4

Tunisia

17.0

(5.7)

11.3

Total1

58.4

5.9

64.3

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.

Notes on calculation of Reserves and Resources

Calculation of reserves and resources

- The approach for all reserves and resources calculations is consistent with the definitions and guidelines in the Society of Petroleum

Engineers (SPE) 2007 Petroleum Resources Management System (PRMS). The resources estimation 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 and probabilistic summation. Aggregated 1P or 1C may be a conservative estimate and aggregated 3P and 3C may
be an optimistic estimate due to the effects of arithmetic summation. Totals may not exactly reflect arithmetic addition due to rounding.

Reserves

- Cooper Energy undertakes its reserves assessments and incorporates information supplied by the respective Operators (Beach Energy

Limited and Senex Energy Limited).

- The Cooper Basin totals comprise the arithmetically aggregated PEL 92 project fields and the arithmetic summation of the Worrior Field

project reserves. The 1P, 2P and 3P reserves totals respectively include 0.03, 0.05 and 0.09 MMbbl oil reserves used for field fuel.

- The Indonesia totals include removal of non-shareable oil (NSO) and comprise the arithmetically aggregated Tangai-Sukananti KSO project

fields. Totals are derived by arithmetic summation.

Contingent Resources

The contingent resources assessment includes resources in the Gippsland Basin, in the PEL 92 Joint venture (PRLs 84-104) and PEL 90K in
the Cooper Basin, the Tangai-Sukananti KSO, Indonesia, and in the Hammamet West Field in the Bargou Permit, offshore Tunisia.

- The following assessments have been released to the ASX: Sole Field on 26 November 2015 and 25 May 2015, Manta Field on 16 July

2015, Basker and Manta fields on 18 August 2014, and Hammamet West Field on 28 April 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.

- Contingent resources in the Sole Field in VIC/RL3, Gippsland Basin, offshore Victoria, were re-assessed by Cooper Energy as a result of

technical reviews associated with the front-end engineering and design (FEED) process. The contingent resources have been assessed using
probabilistic simulation modelling for the Kingfish Formation at the Sole Field. The conversion factor of 1 PJ = 0.172 MMboe has been used
to convert from Sales Gas (PJ) to million barrels of oil equivalent (MMboe).

- Contingent resources in the Basker Field in VIC/RL13, VIC/RL14 and VIC/RL15 (formerly VIC/L26, VIC/L27 and VIC/L28), Gippsland Basin,
offshore Victoria, have been assessed using deterministic simulation modelling for the Intra-Latrobe Group. Contingent resources for the
Basker Field reservoirs have been aggregated by probabilistic summation. The conversion factor of 1 PJ = 0.172 MMboe has been used to
convert from Sales Gas (PJ) to million barrels of oil equivalent (MMboe).

- Contingent resources in the Manta Field in VIC/RL13 and VIC/RL14 (formerly VIC/L26 and VIC/L27), Gippsland Basin, offshore Victoria,

have been assessed using deterministic simulation modelling and probabilistic resource estimation for the Intra-Latrobe and Golden Beach
Sub-Group. Contingent resources for the Manta Field reservoirs have been aggregated by probabilistic summation. The conversion factor
of 1 PJ = 0.172 MMboe has been used to convert from Sales Gas (PJ) to million barrels of oil equivalent (MMboe).

- Contingent resources in Hammamet West Field in the Bargou permit, offshore Tunisia, have been assessed using probabilistic Monte Carlo

statistical methods. Conversion factors for the Hammamet West Field are 1 boe = 5,620 scf.

Qualified Petroleum Reserves and Resources Evaluator Statement
The information on Cooper Energy’s petroleum reserves and resources assessment 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
Exploration Manager, holds a Bachelor of Science (Hons), is a member of the American Association of Petroleum Geologists and the Society
of Petroleum Engineers, is qualified in accordance with ASX listing rule 5.41, and has consented to the inclusion of this information in the
form and context in which it appears.

Review of Operations
Hector Gordon, Executive Director Exploration and Production

Cooper Energy’s operations primarily comprise:

• Oil production in the Cooper Basin (onshore Australia) and the

South Sumatra Basin (onshore Indonesia).

• Pre-development activities associated with the Sole and Manta

gas fields in the offshore Gippsland Basin.

• Exploration for oil and gas in the Cooper, Otway and Gippsland basins.

Highlights of the year’s activities were:

• Sole gas field FEED studies progressed to plan.

• Sole Field 2C contingent resources upgrade by 15 PJ to 121 PJ.

• Manta Field 2C contingent resources upgrade to 21.4 MMBoe.

• Unrisked prospective resources upgrade at Manta and Chimaera to

Best Estimate (P50) of 105.0 MMboe and 45.1 MMboe, respectively.

• Bunian-4 results increased reserves by 0.02 MMbbl in the

Bunian oil field, Sumatra.

Orbost Gas Plant

Production

Cooper Energy’s oil production for the year totalled 0.46 MMbbl, 70% of which was derived from the
company’s Cooper Basin tenements. This is a 2% decrease on the previous year, primarily as a result of
natural decline from the company’s Cooper Basin fields that was offset by increased production from
Indonesia arising from the success of the Bunian-3 development well.

Production MMbbl

Cooper Basin, Australia

South Sumatra, Indonesia

Total

Drilling

2015

0.40

0.08

0.48

2016

0.32

0.14

0.46

Cooper Energy participated in the drilling of one well, Bunian-4, in the Tangai-Sukananti KSO, Indonesia,
during the year. This well successfully appraised the key TRM3 Sand reservoir and discovered a new oil and
gas pool in the GRM Sand. This resulted in an upgrade of field reserves.

Type

Area

Tenement

Well

Development

South Sumatra

Tangai-Sukananti KSO

Bunian-4

Result

Oil Well*

* Cased and suspended as a future oil production well.

Review of Operations

Gippsland Basin

VIC TORI A

Orbost

EAST E R N G

Sydney

E LIN E

S P I P

Orbost Gas Plant (50%)

M e l b o u r n e

Lakes Entrance

Patricia-Baleen

Longtom

Tuna

Kipper

VIC/RL3 (50%)

Sole

Sole-2

Sole-1

Snapper

Marlin

Flounder

Chimaera

Manta
Basker

Gummy

VIC/RL15 (100%)

Fortescue

VIC/RL14 (100%)

VIC/RL13 (100%)

Cooper Energy tenement

Gas field

Oil field

Gas well

Gas pipeline

Oil pipeline

Kingﬁsh

kilometres

Plan area

TAS

Sole pipeline in FEED

Pipeline options

Gippsland_49AR16

Cooper Energy’s interests in the
Gippsland Basin comprise:

– a 50% interest in VIC/RL3 which

holds the Sole gas field;

– a 100% interest in, and

Operatorship of, VIC/RL13, VIC/
RL14 and VIC/RL15 (formerly VIC/
L26, VIC/L27 and VIC/L28) which
contain the Basker and Manta
oil and gas fields (“BMG”). These
fields, previously developed for
oil production, are currently shut-in
pending potential development
for gas.

Cooper Energy holds 100% title to
VIC/RL13, VIC/RL14 and VIC/RL15
following advice from 35% interest
holder Beach Energy in May 2016
of its intention to withdraw from the
BMG joint venture, effective from
27 October 2016. Beach Energy has

contractual obligations under the
JOA in respect of their participating
interest (35%) until that date and
retains its share of abandonment
liabilities until October 2021.

– a 50% interest in the Orbost
Gas Plant, onshore Victoria.
The plant which is in proximity
to the Gippsland Basin gas fields
and connected to the Eastern
Gas Pipeline, is currently in care
and maintenance.

Sole Gas Project and Orbost
Gas Plant

The Sole Gas Project is being
progressed for a final investment
decision (FID), with first gas predicted
for early in calendar year 2019.

Front End Engineering and Design
(FEED) works progressed through

the year and were substantially
completed by August 2016.
The project is expected to comprise
a horizontal development well,
optimised to maximise production
potential, retaining the option for
a second well if appropriate. Gas
produced from the field will be
transported by a 12-inch diameter
subsea pipeline to an upgraded
Orbost Gas Plant from which point it
will enter the Eastern Gas Pipeline.
In parallel to the engineering activity,
work was undertaken to secure the
state and federal regulatory approvals
necessary to take the project to the
implementation phase.

Commercial negotiations resulted in
the announcement of two agreements
for gas sales during the year; with O-I
Australia for 1.0 PJ per annum and with
AGL for 6.6 PJ per annum. The total
gas contracted to date of 7.6 PJ/year
represents 61% of Cooper Energy’s
share of production from Sole.

Subsurface geological and reservoir
engineering studies during the year
resulted in a 2C resource upgrade of
30 PJ to 241 PJ (100% Joint Venture).

Manta Gas Project

The Manta Gas Project has the
potential to produce approximately
24 PJ of gas per annum for supply
to eastern Australian gas users,
with additional revenue from the
condensate production.

A seismic inversion project was
completed in July and the results
were integrated into the under-
standing of the reservoir and
hydrocarbon distribution of Manta.
This work, together with dynamic
simulation modelling, was used
to re-assess the contingent gas
resources in Manta as 106 PJ
of 2C contingent resources plus a
further 11 PJ of Best Estimate
risked prospective gas resources.
Additionally, 2C contingent resources
of 2.6 MMbbl of condensate are
assessed (all 100% Joint Venture).

Review of Manta, and the adjacent
Chimaera East prospects in VIC/
RL13, VIC/RL14 and VIC/RL15 also
resulted in a re-assessment of Best
Estimate prospective resources in
the two prospects. Manta is now
assessed as holding Best Estimate
prospective resource1 of 105 MMboe
comprising 526 PJ of gas, 12.9 MMbbl
of condensate and 1.5 MMbbl of oil.
Chimaera East is assessed as holding
Best Estimate prospective resource1
of 45 MMboe, comprising 229 PJ of
gas and 5.6 MMbbl of condensate.

The upgrade includes new estimates
for deeper target levels and is in
addition to the contingent resources
noted earlier.

The revised prospective resources
assessment is based on new
interpretation of reprocessed 3D
seismic which has highlighted
additional prospectivity at target levels
both shallower and deeper than have
been tested by the existing wells.

It is anticipated the Manta prospective
and contingent resources, can be
tested with a single dual-purposed
appraisal/exploration well.

The Manta development concept
includes a subsea tie-back to
the Victorian coast and processing
via the existing Orbost Gas Plant.
The development case is enhanced by
the scope that exists for cost savings
and synergies through use of existing
adjacent facilities and coordination
with the development of the Sole gas
field. Potential cost-saving synergies
exist in subsea control systems,
common equipment specifications
and shared operational expenses.

1. The estimated quantities of petroleum that

may be potentially recovered by the application
of future development project(s) relate to
undiscovered accumulations. These estimates
have both an associated risk of discovery and
a risk of development. Further exploration,
appraisal and evaluation is required to
determine the existence of a significant quantity
of potentially moveable hydrocarbons.

To Eastern Gas Pipeline

Horizontally
drilled
underground
shore crossing

Existing Orbost Gas Plant
Upgrade to process Sole Field gas

Existing Patricia-
Baleen Pipeline

Control umbilical

Sole Gas Pipeline

Subsea umbilical termination unit

Sole wellhead

Gippsland_51AR16

Phase 1 development schematic: Sole Gas Project plan

Pipeline end manifold

Sole drill centre
(water depth 125m)

MSS
-720m

-740m

-760m

-780m

-800m

-840m

-860m

North west
-1000m

Sole-2

1000m

2000m

3000m

Sole-1
4000m

5000m

South east
6000m

DST 1: 771m to 785mRT
20.6 MMscf/d Dry gas
(94% CH, 0.59 SG, <1 bbl/MMscf CGR)

Lakes Entrance Formation

Core 748-789mTVDSS
Av. Ø = 33%
Av. K = 3000mD

Marl (seal)
Coarse sandstone (2000-6000mD)
High GR sandstone (1000-2000mD)
Argillacaceous sandstone (100-400mD)
Gas zone

Lakes Entrance Formation

-820m

Top L a t r

o be Gro u

GWC -816.5m TVDSS

VIC/RL3

785

5
800

795

Location

805

810

815

Location of section

Sole 2

755
6
7

5
7 6 0

765

7 7 5

7 8 0

7 8 5

7 9 0
795

800

5
0
8

805
Sole 1

805

8 0 0

Base Kingfish Formation

Vertical exaggeration 30:1

kilometres

Gippsland 52inset

GWC

Gippsland_52AR16

Cross-section of Sole gas field

North west

Proposed Manta 3

Manta 1
4000m

South east

MSS
-2600m

-2800m

-3000m

-3200m

-3400m

-3600m

-3800m

-4000m

-4200m

-4400m

Gas zone

Prospective gas zone

Oil zone

Prospective oil zone

Volcanics

Sands

IL1
IL2
IL3 IL4
IL5
IL6
IL7
IL7.5

IL7.3

GB0

GB1
GB2
GB3
GB4/5

GB6

GB7

GB8

Base GB

Gippsland_53AR16

Cross-section of Manta

Review of Operations

Cooper Basin

139°20'

139°40'
39 40

-27°40'

100 101

96
Rincon
North

Rincon

e
e
r

r
e
p
o
o
C

Cooper Energy tenement

Other tenements

Oil field

Gas field

Oil pipeline

Gas pipeline

Callawonga

100

PRLs 85 to 104 (25%) (ex ‘PEL 92’)

89
Parsons

Windmill

Sellicks

Christies
Silver Sands

102

Elliston

-28°

Perlubie
Perlubie South

Butlers

Germein

101

104

103
Lycium Hub

Plan area

TAS

oper 66AR16
Cooper_66AR16

Cooper Energy holds interests
in three exploration licenses,
28 retention licences and eleven
production licences in the South
Australian Cooper Basin.

The company’s activities are primarily
focussed on tenements held by the
PEL 92 Joint Venture* (‘PEL 92‘)
on the western flank of the basin,
which provided approximately 65%
of Cooper Energy’s total production
in FY16. The Worrior Field (PPL 207)
supplied 4% of Cooper Energy’s total
production for the year.

kilometres

PEL 93 (30%)

* The PEL 92 Joint Venture

(Cooper Energy: 25% interest)
holds 20 Petroleum Production
Licences and 28 Petroleum
Retention Licences: PRLs 85-
104 (all of which were originally
licenced as PEL 92). The PEL
110 Joint Venture (COE: 20%)
holds 8 Petroleum Retention
Licences: PRLs 183-190 (all of
which were originally licensed
as PEL 110).

Oil exploration is also being
undertaken in PEL 93 and in the
company’s tenements along the
northern flank of the basin: PELs
90K and 100, and PRLs 183–190
(formerly PEL 110)*.

Cooper Energy’s share of oil
production from its Cooper Basin
tenements – PEL 92 and PPL 207
(Worrior Field) – during the year
totalled 0.32 MMbbl, 21% below that
achieved in the previous year. The
decrease in production was primarily
due to natural field decline, which
was offset by the contributions from
Callawonga-10 and Callawonga-11,
which were brought online in
September 2015.

139°30'

139°40'

139°50'

Worrior

PPL 207

1 kilometre

Inset

PEL 93 (30%)

Plan area

TAS

Cooper Energy tenement

Other tenements

Oil field

Gas field

Gas pipeline

Oil well

Oil show

See inset

Worrior

PEL 93 (30%)

-28°20'

O P E R B A SIN

C O

-28°30'

kilometres

-28°40'

Cooper_67_AR16

-26°40'
-26°40'

140°20'
140°20'

140°40'

-26°40'

Cooper Energy
tenement

Other companies’
tenement

Oil field

Gas field

Oil pipeline

Gas pipeline

3D seismic survey

Plan area

TAS

-27°00'
-27°00'

PRLs 183-190 (20%) Ex PEL 110

PRL 183

PRL 187

PRL 184

PRL 188

PRL 185

PRL 189 PRL 190

PRL 186

Dundinna 3D
seismic survey

Tarragon

PEL 100 (19.17%)

Verona

Gudi

140°20'

Cuttapirrie

Moondie

-27°00'

Kiwi

Keleary

Telopea

Cleansweep

PEL 90 (25%)

kilometres

140°40'

Cooper 68AR16

The PEL 92 Joint Venture focussed
activities on reprocessing and
reinterpretation of the 3D seismic data
in PRLs 85–104 (25% interest) with a
view to replenishing the drilling target
inventory. The subsurface effort has
delineated several new exploration
prospects at the Namur Sandstone
level as well as at deeper reservoir
levels such as the Birkhead, Hutton
and Patchawarra formations.

In addition to exploration studies,
detailed seismic mapping and
reservoir modelling have identified
several infield development
drilling locations in the key fields.
The successful Callawonga-12
development well drilled after year-end
in August 2016 is a location identified
by the studies undertaken during
FY16, and highlights the additional
reserves potential of the PEL 92
fields. Results from these studies
have contributed to an increase in
the EUR (estimated ultimate recovery)
for the Callawonga, Butlers and
Windmill fields which have been
incorporated in Cooper Energy’s
year-end reserves statement.

In PPL 207 (30% interest), a
successful zone change to the
McKinlay Member in Worrior-8
resulted in increased production.
The Operator has implemented cost-
saving measures that have lowered
the field operating costs. During the
year, the Operator conducted a full
field review of opportunities to add
incremental reserves or accelerate
production. Plans to drill additional
development wells are under review.

In the northern Cooper Basin permits
PEL 90K (25% interest), PEL 100
(19.165% interest) and PEL 110 (20%
interest), the Dundinna 3D seismic
survey was the focus of a seismic
inversion project. The project was
completed during the year and the
Operator is incorporating the results
into a regional prospectivity study that
will form the basis of a review of the
prospect inventory in FY17.

Review of Operations

Otway Basin

Kingston SE

SOUTH AUSTRALIA

Naracoorte

ROBE TROUGH

Robe

PEL 494 (30%)

PRL 32 (30%)

Cooper Energy tenement

Gas field

Gas pipeline

Depositional trough

ST CLAIR TROUGH

Beachport

Millicent

Penola

Katnook

Nangwarry

VICTORIA

PEP 171 (25%)

Mount Gambier

ARDONAC

HIE T

Hamilton

PEP 150 (20%)

PEP 168 (50%)

Cobden

Portland

Warrnambool

Plan area

TAS

kilometres

Cooper Energy holds interests in four
exploration licences and one retention
licence in the onshore Otway Basin,
covering a total area of 7,292 km2.
The company’s primary focus in this
region is exploration for oil and gas
plays associated with the Casterton
and Sawpit formations, primarily
within the Penola Trough.

Analysis of data from Jolly-1 ST1 and
Bungaloo-1, drilled in FY14 within
the South Australian portion of the
basin, was completed. The results
have assisted with the identification of
a number of opportunities for future
evaluation of the deep plays in the
Penola Trough.

Reprocessing and interpretation of the
Haselgrove 3D seismic survey (146
km2) and 222 km of 2D seismic data
in PEL 494 was undertaken.

PELs 494 and 495 were consolidated
into a single licence (PEL 494) and
renewed for an additional five-year
term. In accordance with regulatory
requirements, the renewal process
included relinquishment of 50% of
the combined licence area. PEL 494
has been renewed to March 2021.
The new work commitment requires
the drilling of one well before March
2018 and acquisition of 100 km2 3D
seismic before March 2020.

Cooper Energy surrendered PEL 186
in South Australia and withdrew from
PEP 151 in Victoria. Applications to
suspend and extend PEPs 150, 168
and 171 for a further 12 months due
to the ongoing moratorium on gas
exploration operations were submitted
to the Victorian regulatory authority.

SHIPWRECK TROUGH

Otway 35AR16

Subsequent to year-end, the
Victorian government announced a
permanent ban on the exploration
and development of all onshore
unconventional gas in Victoria,
including hydraulic fracturing and
coal seam gas. In addition, the
government plans to legislate that the
current moratorium on exploration
and development of all onshore
conventional gas will be extended
to 30 June 2020. Cooper Energy
and its joint venture partners are
currently reviewing their options and
future plans relevant to the onshore
permits in Victoria.

Indonesia

TMB-06

Tanjung Miring
Barat

Cooper Energy permit

Oil field

Oil well

Abandoned oil well

Dry well

Indonesia_124_AR16

In Indonesia, Cooper Energy holds
a 55% interest in, and operates,
the Tangai-Sukananti KSO tenement
in the onshore South Sumatra Basin.
The company completed sale of the
Sumbagsel PSC and the Merangin
III PSC exploration permits during
the year.

Tangai-Sukananti KSO (55%
interest and Operator)

Operations in the Tangai-Sukananti
KSO are mainly focused on the
Bunian oil field, which was discovered
in 1998. To date, the field has
produced over 1.25 million barrels
of oil, predominantly from the TRM3
Sand in Bunian-1, which, prior to
commencement of production from
Bunian-3 ST2 in May 2015, was
the only producing zone in the field.
Oil is also produced from two wells in
the nearby Tangai oil field.

104°55'

Bunian-2

INDONESIA

Bunian-1

Bunian-3ST1

Bunian

Bunian-3ST2

Bunian-4

Kupang-1

Tangai-Sukananti KSO (55%)

Sukananti-1

Tangai-1

Tangai-4

Tangai-3

Tangai-2

Tangai

-3°35'

kilometres

Two operations were undertaken
to increase oil production from the
KSO during the year; the drilling of
the Bunian-4 appraisal well and a
workover of Tangai-3.

Bunian-4 was drilled in July-
August 2015 to appraise the extent
of the TRM3 and K1 Sand oil pools
by attempting to locate an oil-water
contact in a downdip location.
The main reservoir, the TRM3 Sand,
was intersected 17 metres (m) higher
than prognosed and no oil-water
contact was intersected. The TRM3
Sand was 9.1m thick with 7.1m of
net oil pay interpreted.

The K1 Sand at Bunian-4, a new
oil and gas pool discovered at the
Bunian-3ST2 well in April 2015,
was intersected 20m higher than
prognosed. Although water-bearing
at this location, the result contributed
to an increase in proven reserves.

In addition to the TRM3 and K1
Sand results, a new oil pool was
discovered in the GRM Sand of the
Talang Akar Formation (between the
TRM3 and the K1 Sands). The sand
was 4.9m thick with 4.1m of net
oil pay interpreted.

The results at Bunian-4 led to an
increase in 2P oil reserves in the
field at 30 June 2016 to 1.55 MMbbl
(Cooper Energy share), which
is an increase of 0.02 MMbbl and
offsets FY16 field production of
0.23 MMbbl oil.

Bunian-4 will be completed as an
oil producer from the TRM3 and GRM
Sands following the installation of
artificial lift in FY17.

The workover of Tangai-3 in
June 2016 resulted in the well
re-commencing production in that
month. Tangai-3 produced at an
average rate of 40 bopd during FY16.

Total production from the KSO
for the year averaged 743 bopd
compared to an average of 383 bopd
in the previous year, notwithstanding
constraints imposed by trucking
export and the handling capacity of
facilities. The new K1 Sand oil
pool, discovered by Bunian-3 ST2,
produced 55,561 bbl of oil over
the four months from August to
December 2015 at an average rate
of 463 bopd of oil, proving the high
productivity of the reservoir.

Studies undertaken during, and
subsequent to, FY16 will contribute
to a Plan of Further Development
for Bunian, which is expected to
include drilling and the installation of
increased export capacity during the
2017-2018 calendar years.

Cooper Energy does not expect to
participate directly in the ongoing
development of the field as its interest
in the Tangai-Sukananti KSO is
subject to a divestment process.

Review of Operations

Tunisia

10°E

37°N

Tunis

11°E

12°E

13 E
13°E

Bargou Permit (30%)

Lambouka

Dougga

Pantelleria Island
(Italy)

Aster

Zibibbo

Tazerka

Birsa

Yasmin

Nabeul Permit

Neopolis

Hammamet

Maamoura

Fushia

Tafernine

Zelfa

MEDITERRANEAN SEA

Plan area

TUNISIA

Cosmos

Oudna

Baraka
Baraka SE

Hammamet Permit

Lotus

Baraka South

Sbeitla

El Mediouni

36°N

Halk El Menzel

kilometres

Cooper Energy tenement

Other tenements

Oil field

Gas field

Gas pipeline

to be drilled, as well as unspecified
damages for a claimed breach
of the operating agreement. Cooper
Energy believes the claim to be
without basis and denies any liability
for activities undertaken during an
extension period of the permit in
which it has elected not to participate.
The company intends to defend the
claim vigorously.

Nabeul Permit

The terms of completing an exit from
the Nabeul permit were agreed with
the Tunisian government authority
and the Joint Venture has paid
compensation of US$3.2 million
(COE share US$2.7 million) to fulfil
its remaining permit obligations
and has now completed the exit.

Sousse

TUNISIA

Monastir

Tunisia_39AR16

Bargou Permit (30% interest
and Operator)

The Bargou permit Joint Venture
acquired a 504 km2 3D seismic
survey as part an amended work
program during FY16. Interpretation
of the seismic data will be completed
in 2016 and abandonment of
the Hammamet West well will be
completed in FY17. This is expected
to fulfil the Joint Venture’s obligations
under the amended work program.

Hammamet Permit (previously
35% interest)

Cooper Energy elected not to
participate in the Hammamet permit
extension and withdrew from the
permit. As reported to the ASX, the
company was subsequently served
with a Request for Arbitration by
the remaining joint venture partners
(Medco Ventures International
(Barbados) Ltd and DNO Tunisia AS)
seeking security from Cooper Energy
for its share of a well which is yet

Health Safety Environment and
Community (HSEC)

Highlights – Health and Safety

Initiatives

Community

The Cooper Energy team achieved an
outstanding safety performance during
the year, with staff and contractors
working a total of 963,000 hours with
zero Lost Time Injuries and zero Total
Recordable Cases. Total Recordable
Cases comprises the sum of Lost Time
Injuries, Alternate Duties Injuries and
Medical Treatment Cases. Particular
recognition in achieving this result
is due to our field personnel in South
Sumatra, Indonesia, during both
drilling and ongoing oil production
operations as well as to the offshore
seismic team in Tunisia.

Environment

No recordable environmental incidents
occurred during the financial year.

Our HSEC philosophy is based
around the principles of care,
mindfulness and continuous
improvement. A specific initiative
underpinning this philosophy is
to embed the principles of the
High Reliability Organisation in our
culture. In order to progress this,
the company has focused on a
specific number of high potential
near misses or accidents from
elsewhere in the industry which
have particular relevance for our
own operations. These events are
communicated to our workforce
and then processes and systems
assessed to identify and close gaps
and to proactively incorporate
lessons learned from within the
wider industry.

Cooper Energy has a long term
commitment to contribute to and
to engage with communities in
which it operates. An example is the
“Making a Difference” volunteering
programme in Adelaide, where
Cooper Energy staff contributed
their time and resources to a
variety of charitable organisations
including the Hutt Street Centre for
the homeless, Foodbank, Juvenile
Diabetes Research Fund and Nature
Foundation SA.

While the company allocates time
to participate in these activities,
it is notable that the culture has
developed so that more than 80% of
the time contributed actually occurs
outside working hours.

Cooper Energy team members Jacinta Lowry, Tim Cotton, Zacc Paparella and Simon Brealey
participating in native vegetation planting at the Nature Foundation SA Para Woodlands
property. Para Woodlands is a former farming property where the Nature Foundation SA is
working to restore the natural ecosystem to conserve wildlife.

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/Perlubie South)

PPL 248 (Rincon)

PPL 249 (Elliston)

PPL 250 (Windmill)

PEL 90 (Kiwi sub-block)

PRLs 85-104 (ex-PEL 92)

PEL 93

PEL 100

25%

30%

25%

30%

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

144.6

Senex Energy

Exploration

Onshore

1,889.3

Beach Energy

Exploration

Onshore

621.8

Senex Energy

Exploration

19.17%

Onshore

296.5

Senex Energy

Exploration

ex PEL 110 1

20%

Onshore

727.5

Senex Energy

Exploration

Otway Basin

State

Tenement

Interest

Location

Area (km2)

Operator

Activities

South Australia

PEL 494

PRL 32

PEP 150

PEP 168

PEP 171

Victoria

Gippsland Basin

State

Victoria

30%

20%

50%

25%

Onshore

1,274

Beach Energy

Exploration

36.9

Beach Energy

Exploration

3,212

Beach Energy

Exploration

795

Beach Energy

Exploration

1,974

Beach Energy

Exploration

Tenement

Interest

Location

Area (km2)

Operator

VIC/RL3 (Sole)

VIC/RL13

VIC/RL14

VIC/RL15

50%

100%

Offshore

Activities

Retention

201

Santos

Cooper Energy

Retention

Cooper Energy

Retention

Cooper Energy

Retention

1. Ex PEL 110 consists of PRLs; 183, 184, 185, 186, 187, 188, 189 and 190.

Orbost Gas Plant, Gippsland Basin, Victoria

Region: Indonesia

South Sumatra Basin

Tenement

Interest

Location

Area (km2)

Operator

Tangai – Sukananti KSO

55%

Onshore

18.3

Cooper Energy

Region: Tunisia

Gulf of Hammamet

Tenement

Bargou

Interest

Location

Area (km2)

Operator

30%

Offshore

4,616

Cooper Energy

Activities

Production

Activities

Exploration

Board of Directors

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

Independent
Non-Executive Director
Ms Alice J. M. Williams
B.Com, FAICD, FCPA, CFA

Appointed 12 October 2011

Appointed 28 August 2013

Experience and expertise

Mr Schneider has over 30 years of
experience in senior management roles
in the oil and gas industry, including 24
years with Woodside Petroleum Limited.
He has extensive corporate governance
and board experience as both a
non-executive director and chairman
in resources companies.

Current and other directorships in
the last 3 years

Mr Schneider is a former director of
Comet Ridge Limited ASX: COI (2003
– 2014) and Green Rock Energy Limited
ASX: GRK (2010 – 2013).

Special Responsibilities

Mr Schneider is Chairman of the
Remuneration and Nomination
Committee and member of the Audit
and Risk Committee.

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),
Guild Group, Defence Health and Port of
Melbourne Corporation. Ms Williams is a
former council member of the Cancer
Council of Victoria.

Special Responsibilities

Ms Williams is Chairman of the Audit
and Risk Committee and a member
of the Remuneration and Nomination
Committee.

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 a member of the
Remuneration and Nomination
Committee and the Audit and
Risk Committee.

Managing Director
Mr David P. Maxwell
M.Tech, FAICD

Appointed 12 October 2011

Executive Director
Exploration and Production
Mr Hector M. Gordon
B.Sc. (Hons). FAICD

Appointed 26 June 2012

Executive
Management
team

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.

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 Strait
Oil Company Ltd ASX: BAS (since 2014)
and various wholly owned subsidiaries
of the Company. He is a former director
of ERO Mining Limited (2011 – 2013).

Special Responsibilities

Mr Maxwell is responsible for the day to
day leadership of Cooper Energy. He is
the leader of the management team.

As a part-time executive of the Company,
Mr Gordon is responsible for overseeing
exploration and production activities and
providing technical expertise in these
areas. He is also Chairman of the HSEC
Management Committee and the
Indonesian Management Committee.

Managing Director
David Maxwell
M.Tech, FAICD

Executive Director –
Exploration & Production
Hector M. Gordon
BSc (Hons), FAICD

Operations Manager
Iain MacDougall
BSc (Hons)

Exploration Manager
Andrew Thomas
BSc (Hons)

Commercial & Business
Development Manager
Eddy Glavas
B.Acc., CPA, MBA

Chief Financial Officer,
Company Secretary
Jason de Ross
B.Ec., ACA, MBA, F Fin, GAICD

Company Secretary and
Legal Counsel
Alison Evans
B.A., LLB

Key Performance Indicators

Operational

Annual production

Proved & Probable Reserves

Wells drilled

Exploration wells spudded

12 months
to 30 June

MMbbl

number

2009

2010

2011

2012

2013

2014

2015

2016

0.49

1.91

0.47

2.00

0.41

2.47

0.52

1.88

0.49

2.16

0.59

2.01

0.48

3.08

Exploration success rate

percent

60%

50%

25%

Cumulative exploration success rate percent

30%

27%

23%

27%

26%

24%

22%

Reserve Replacement Ratio

198%

119%

215%

(14)%

157%

75%

323%

Financial

Oil sales revenue

$ million

41.6

40.0

39.1

59.6

53.4

72.3

39.1

0.46

3.00

n/a

22%

83%

27.4

0.9

Other revenue

EBITDA

Profit before tax

$ million

4.2

5.2

5.0

Profit after tax / (loss)

$ million

(2.8)

4.3

8.0

7.2

1.2

5.1

(6.0)

(5.5)

(10.3)

Cash & term deposits

$ million

93.4

92.5

72.4

Investments

Working capital

Accumulated profit

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

47.9

20.2

51.7

23.8

39.0

1.3

22.0

(63.5)

(34.8)

2.8

1.9

36.9

(58.4)

(37.4)

31.2

(18.8)

(26.0)

49.1

26.0

41.2

39.4

49.8

1.9

1.0

43.0

44.2

45.7

(17.7)

(52.6)

38.7

43.7

42.9

91.6

Shareholders equity

$ million

123.3

125.1

114.9

136.9

137.2

167.8

103.9

Earnings per share

cents

(1.0)

0.4

(3.5)

2.8

0.4

6.4

(19.2)

(10.1)

Return on shareholders funds

percent

(2.3)%

1.0% (8.6)%

6.7%

0.9%

14.4% (61.1)% (38.0)%

Total shareholder return

percent

(3.2)% (17.8)% (2.7)%

25.0% (16.7)%

34.7% (51.5)% (12.2)%

Average oil price

A$/bbl

86.76

87.02

95.42

114.63

112.31

124.08

85.48

60.75

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

million

291.9

292.6

327.3

329.1

329.2

331.9

435.2

Market capitalisation

$ million

131.4

108.3

105.3

147.3

123.4

166.3

81.4

93.6

Shareholders

number

7,596

6,537

5,573

5,485

5,284

5,122

5,103

4,931

Cooper Energy Limited and its controlled entities

Financial Report

For the year ended 30 June 2016

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

Summary of Significant Accounting Policies

Segment Reporting

4 Revenues and Expenses

Income Tax

Earnings Per Share

7 Cash and Cash Equivalents and Term Deposits

Trade and Other Receivables

9 Prepayments

10 Available for sale investments

11 Equity instruments at fair value through other

comprehensive income

12 Assets held for sale and discontinued operations

13 Investments in associate

14 Oil Properties

15 Impairment

16 Property, Plant & 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 Early adoption of AASB 9

24 Hedge Accounting

25 Commitments and Contingencies

26 Interests in Joint Arrangements

27 Related Parties

28 Share Based Payment Plans

29 Auditors’ Remuneration

30 Parent Entity Information

31 Events After the Reporting Period

Directors’ Declaration

Independent Audit Report

Auditors’ Independence Declaration

Securities Exchange and Shareholder Information

100

102

105

106

107

109

110

Operating and Financial Review
For the year ended 30 June 2016

Summary Overview

The Company’s operating and financial results for the year ended 30 June 2016 (”the year”) have three significant features:

• the impact of, and response to, lower oil prices;

• advancement of the gas strategy, towards the Final Investment Decision (FID) on the first phase, the Sole Gas Project; and

• concentration of activities and resources on Australia, as the exit from international operations approaches completion.

The Company recorded a statutory loss for the period of $34.8 million, mainly due to impairments recorded against the carrying value
of exploration and evaluation assets brought about by the lower near term oil price outlook, and impairments to Indonesian assets held
for sale. Exclusive of these significant items, Cooper Energy recorded an underlying loss of $2.8 million. Cash flow of $7.9 million was
generated from operating activities. 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 engaged in the commercialisation of gas resources in the Gippsland
Basin to supply gas to south eastern Australia customers, oil production and exploration in the western flank of the Cooper Basin and
exploration in the Otway Basin.

While the focus of the Company’s activities is on the Australian energy sector, its portfolio in FY16 included a number of residual
international production and exploration assets. During the year these assets were either divested or plans implemented to divest or
withdraw in the near future.

Safety

The company recorded a zero Total Recordable Case Frequency Rate (TRCFR) and a zero Lost Time Injury Frequency Rate (LTIFR) for
the 12 months to 30 June 2016. This compares with the previous year’s TRCFR of 4.2 per million hours worked and a LTIFR of 1.04
incidents per million hours worked.

Production

Cooper Energy produced 0.47 million barrels of oil in the year at an average direct cost of A$29.71/bbl, which compares with 0.48 million
barrels (average direct cost of A$36.76/bbl) in FY15. The movement between periods is attributable to lower production from the Cooper
Basin, where capital expenditure was reduced and no drilling conducted during the year. As discussed under the heading ‘Outlook’ later
in this review, it is planned that drilling will resume in FY17.

The Cooper Basin contributed 0.32 MMbbl, or 68%, of the Company’s oil production during the year, with the balance sourced from the
Tangai-Sukananti KSO in the South Sumatra Basin, Indonesia which is currently subject to a divestment agreement.

Gippsland Basin Gas Projects

The Company’s Gippsland Basin gas resources are the focal point of the company’s growth strategy and accounted for 70% of capital
expenditure during the year. Progress made has seen the Company increase its contingent and prospective resources, secure Heads of
Agreement for gas sales, and near complete Front End Engineering and Design (FEED), for development of the Sole Gas Project.

Cooper Energy’s Gippsland Basin gas interests comprise:

• a 50% interest in VIC/RL 3, which holds the Sole gas field;

• a 50% interest in the Orbost Gas Plant, which is currently in care and maintenance and ideally located to process gas from Sole and

other Gippsland Basin fields; and

• a 100% interest in VIC/RL 13-151, which hold the Manta gas field and the Basker oil and gas field. Beach Energy which held a 35%

interest in the licences and has notified of its intention to withdraw and remains liable for a 35% participating interest until the effective
date of withdrawal, being 27 October 2016.

Sole Gas Project

The FID for the Sole Gas Project is expected before the end of 2016. The case for commercialisation of Sole has been reinforced by
milestones and developments during FY16 including:

• announcement of an upwards revision to Contingent Resources for the field on 26 November 2015, with the effect that Sole is now

assessed to hold 241 PJ2 of gas (2C Contingent Resources; Cooper Energy share 120.5 PJ) compared with 211 PJ previously;

• FEED conducted over the course of FY16 has delivered a technically robust and economic development plan;

• Heads of Agreement for the sale of gas to AGL and O-I Australia, totalling 7.6 PJ pa. This represents 61% of Cooper Energy’s 50% share
of Sole output, thereby providing foundation sales for project FID and permitting further contracting to be optimised for best value; and

1 These tenements were previously the exploration licences VIC L/26, L/27 and L/28
2 Contingent Resources assessed for the Sole gas field and Manta fields were announced to the ASX on 26 November 2015 and 16 July

2015 respectively. Cooper Energy is unaware of any new information or data that materially affects the information provided in that release
and all material assumptions and technical parameters underpinning the assessment provided in the announcement continue to apply.

Operating and Financial Review
For the year ended 30 June 2016

Operations continued
• trading and trends in the Australian energy market during the year and subsequent, which are consistent with the tighter gas supply

anticipated in the company’s gas strategy.

Strategies have been developed for financing the development of Sole and structuring commercial participation for acceptable returns for
shareholders. Specific plans for the Sole Gas Project will be settled prior to FID.

Manta

The Company concluded the Business Case study for the resources located in VIC/RL 13-15. The study identified a sound economic
opportunity for development of the Manta gas field and production of 106 PJ of gas and 2.6 MMbbl of condensate (gross 2C Contingent
Resources2) via the Orbost Gas Plant. The development is contingent on successful appraisal drilling.

Further analysis has identified substantial synergies available through coordinating development of Manta with the Sole gas field.
Commercialisation of Manta, which is a less mature, longer dated asset than Sole, is being pursued with a view to realising the benefits
expected from coordinating resources and activities between the two projects.

Geological studies during the year identified the potential for significant resource additions in the deeper zones below the existing Manta
field (Manta Deep) and the Chimaera East prospects in VIC/RL 13-15. Prospective Resources assessed for these prospects have been
upgraded as a result, and were detailed in the announcement to the ASX on 4 May 2016.

Portfolio management

Portfolio management has been a long-term and ongoing exercise as the Company concentrates its resources around cash-generating
Australian onshore oil production and the development and sale of gas to south eastern Australian customers.

Since 1 July 2015 the Company has sold, or contracted for sale, its Indonesian assets, ceased involvement in two of the three Tunisian
permits in which it was involved, and withdrawn from some Australian tenements. It is expected the Company’s portfolio will consist of
entirely Australian assets in the near term.

In Tunisia, as disclosed in Note 12 to the Financial Statements, Cooper Energy has withdrawn from the Hammamet joint venture (COE
interest 35%) while in the Nabeul joint venture (Cooper Energy interest 85%) the Company exited the permit after agreeing terms with the
government. In the remaining Tunisian tenement, the Bargou permit (COE interest 30%), the joint venture agreed, and is in the process
of completing, a reduced work program consisting of seismic acquisition and well abandonment to fulfil its commitments.

In Australia, the VIC/RL 13-15 offshore Gippsland Basin joint venture parties accepted an offer from the National Offshore Petroleum
Titles Administrator (NOPTA) to convert the permits into Retention Leases with a 5 year term. Otway Basin interests were rationalised with
the relinquishment of PEL 186 and withdrawal from PEP 151.

Exploration and development

The Gippsland Basin gas resources were the principal focus of the Company’s technical activity during the year, including a reassessment
of Contingent Resources and Prospective Resources, the completion of the business case study for Manta and the FEED for Sole.

Exploration and development activities were curtailed to preserve cash in the current low oil price environment. The Company participated
in one well during the year, Bunian-4 a successful oil appraisal/development well in the Tangai-Sukananti KSO, Indonesia, which was
cased and suspended as an oil producer after identifying a new oil pool reservoir.

In the Cooper Basin, activity included the connection of the successful Callawonga-10 and Callawonga-11 wells and facilities optimisation
work in producing fields. Geological studies have identified targets for development and exploration drilling planned for FY17.

Reserves and resources

At 30 June 2016 the company’s reserves and resources were assessed to be 3.0 million barrels (MMbbl), proved and probable reserves,
marginally lower than the corresponding figure of 3.1 MMbbl at the beginning of the year. Contingent Resources (2C) were assessed to be
59.0 million barrels of oil equivalent (MMboe) compared with the FY15 comparative of 58.4 MMboe.

A detailed statement on reserves and resources has been lodged with the ASX on 15 August 2016. Significant features of the statement include;

- 1.7 MMbbl of proved and probable reserves at 30 June are attributable to Indonesia and subject to a contract for sale. Similarly, 2C

Contingent Resources of 17.4 MMboe are attributable to assets in Indonesia or Tunisia which are either subject to a divestment contract
or a withdrawal plan.

- Australian proved and probable reserves at 30 June 2016 were 1.3 MMbbl after production of 0.3 MMbbl during the year. The major
share of the year’s production was replaced by upwards revision to estimates of reserves in producing Cooper Basin oil fields after
technical analysis including seismic reprocessing and remapping.

- 2C Contingent Resources in Australia of 41.6 MMboe includes 213 PJ, of which 121 PJ (21.0 MMboe) is attributable to the company’s

interest in the Sole gas field.

2 Contingent Resources assessed for the Sole gas field and Manta fields were announced to the ASX on 26 November 2015 and 16 July

Operating and Financial Review
For the year ended 30 June 2016

Financial Performance

Cooper Energy recorded a statutory loss after tax of $34.8 million for the 30 June 2016 financial year which compares with the loss after
tax of $63.5 million recorded in the 2015 financial year. The 2016 statutory loss includes a number of items which adversely affected
loss after tax by a total of $32.0 million. These items principally comprise impairments to the Indonesian exploration and evaluation assets
held for sale (included in discontinued operations) and the Otway exploration and evaluation assets.

Financial Performance

Production volume

Sales volume

Sales revenue

Average oil price

Gross profit

Gross profit / Sales revenue

Operating cash flow

Reported loss

Underlying loss

Underlying EBITDA*

MMbbl

$ million

A$/bbl

$ million

FY16

0.465

0.451

27.4

60.75

9.9

36.1

7.9

-34.8

-2.8

1.2

FY15

0.475

0.457

39.1

85.56

14.1

36.1

2.0

-63.5

-1.3

8.1

Change

-0.010

-0.006

-11.7

-24.81

-4.2

0.0

5.9

28.7

-1.5

-6.9

-2%

-1%

-30%

-29%

-30%

295%

45%

-115%

-85%

* 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 loss by adjusting for items unrelated to the underlying operating performance is considered to provide
meaningful comparison of results between periods. Underlying loss and underlying EBITDA are not defined measures under International
Financial Reporting Standards and are not audited. Reconciliations of net loss after tax and Underlying loss and 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 was $2.8 million, compared with an underlying loss after tax of $1.3 million in the previous year. The factors
which contributed to the movement between the periods were:

• significantly lower oil prices. The average oil price of A$60.75/bbl (including hedge benefit of $5.54/bbl) was 29% lower than the 2015

financial year average of A$85.56/bbl. This difference was responsible for an $11.3 million reduction in sales revenue;

• production expenses and royalties were $3.4 million lower in response to lower oil prices;

• amortisation costs were $4.1 million lower mainly due to prior period impairments on oil properties;

• exploration and evaluation expenditure written off was $2.5 million lower, due to lower activities and reversal of prior year accruals;

• general administration costs were $1.2 million lower, due to lower remuneration and consulting costs and reversals of prior year

accruals; and

• income tax benefit was $2.6 million higher, mainly due to the recognition of a deferred tax asset on the current year taxable loss.

Financial Position

Total assets

Total liabilities

Total equity

Total Assets

$ million

FY16

176.3

84.8

91.6

FY15

174.0

70.1

103.9

Change

2.3

14.7

-12.3

21%

-12%

Total assets increased by $2.3 million from $174.0 million to $176.3 million.

Cooper Energy has a strong balance sheet. At 30 June the Company held cash and deposit balances of $49.8 million, equity investments
of $0.8 million and investment in associate of $0.2 million (total investments $1.0 million) and no debt.

Cash and deposit balances increased by $10.4 million over the period after net proceeds from the equity issue of $21.2 million, net
proceeds from the sale of the Indonesian exploration assets of $12.4 million, operating cash flow of $7.9 million and net foreign exchange
and other items of $1.3 million, partially offset by funding exploration and development expenditure of $32.4 million, as summarised in
the chart below.

Operating and Financial Review
For the year ended 30 June 2016

Financial Position continued

Lower quoted share prices for equity investments resulted in investments reducing by $0.9 million over the period.

$ million
Total cash &
investments
41.3

Investments
(at fair value)

1.9

39.4

Cash &
deposits

13.6

-9.9

3.4

0.8

47.3

-32.4

Operating
+7.9

Total cash &
investments
50.8

Investments
(at fair value)

1.0

49.8

1.3

Cash &
deposits

21.2

12.4

Other
+2.5

June 15 Operations General Net Working

Admin

Capital
Movement

Interest Cash after
operating
cash flows

E & D

Proceeds
from sale
of Indo.

FX &
Proceeds
from equity Other

June 16

issue

Exploration and evaluation assets increased $5.6 million from $105.4 million to $111.0 million as a result of Sole FEED, increases to the
rehabilitation provision in VIC/RL 13-15, partially offset by impairments to the value of Indonesian, Otway exploration and Cooper Basin
northern license assets.

Oil properties (including those held for sale of $0.8 million) decreased by $5.7 million from $11.9 million to $6.2 million mainly as a result
of impairments to the value of the Indonesian assets and amortisation, partially offset by capital expenditure during the period.

Trade and other receivables (including those held for sale of $3.9 million) decreased $4.7 million from $12.0 million to $7.3 million, mainly
due to the timing of sales revenue receipts and the decrease in oil prices.

Total Liabilities

Total liabilities increased by $14.7 million from $70.1 million to $84.8 million.

Provisions (including those held for sale of $0.2 million) increased by $22.7 million from $47.1 million to $69.8 million due to an increase
in the rehabilitation provision for VIC/RL 13-15 arising from an increase in the Company’s interest in the permits from 65% to 100% and
an increase in the estimated cost of abandonment. Deferred tax liabilities decreased by $8.8 million from $11.0 million to $2.2 million due
to movements in temporary differences and the recognition of a deferred tax asset on carry forward tax losses.

Total Equity

Total equity has decreased by $12.3 million from $103.9 million to $91.6 million. In comparing equity for the period to the prior
corresponding period the key movements were:

• higher contributed equity of $22.1 million due to shares issued from equity raisings and shares issued on vesting of performance rights

during the period;

• higher accumulated losses of $34.8 million due to the total loss for the 2016 financial year; and

• higher reserves of $0.4 million mainly due to the issue of equity incentives to employees partially offset by negative fair value movements

on the Company’s listed equity investments.

Operating and Financial Review
For the year ended 30 June 2016

Business Strategies and Prospects

Market developments and the Company’s activities during the year are consistent with plans to build a gas business to supply the
opportunities anticipated in south eastern Australia whilst maintaining cash-generating oil production. The technical, operational and
commercial activities required to support the implementation of the Company’s strategy are being conducted in accordance with
disciplined and diligent cost management and the objective of maximising shareholder value.

The first phase of the Gippsland Basin gas business is the Sole Gas Project which is now approaching FID with a completed development
design and plan, foundation sales Heads of Agreement and a strong market outlook. An affirmative FID decision for Sole will trigger a
substantial increase in reserves as Cooper Energy recognises its share (currently 50%) of the 40 MMboe Proved and Probable Reserves
that are expected to be attributable to the field once the development is committed.

Further contracting of the Company’s gas resources in Sole will be conducted with the objective of securing the best value for
shareholders given market conditions. Accordingly, it is intended to retain as much uncommitted gas resource as is prudent for exposure
to the returns expected from short and medium term sales in a tight market.

The second phase of the Gippsland Basin gas business is the appraisal and development of the Manta field which offers a further step
change in production and revenue generation. This project has attracted interest from gas buyers, with an option for 4 PJ pa being held
by AGL under the Heads of Agreement signed in March 2016. Work is ongoing to advance the commercialisation of the Manta resource
with near term priorities including reconstituting the VIC/RL 13-15 joint venture with parties keen to participate in Gippsland Basin gas
development and planning for the Manta-3 appraisal well with a view to drilling from the final quarter of calendar 2017.

Oil production from the western flank of the Cooper Basin is the Company’s current source of cash generation. The financial and
technical robustness of the PRL 85-104 assets (previously PEL 92) are apparent in the year’s recorded results despite low oil prices and
a suspension of drilling. Cash costs of production are well below current oil prices.

Investment in technical analysis of the PRL 85-104 acreage and other assets in the Cooper Basin is continuing to identify low risk
exploration, appraisal and development opportunities. It is expected that ongoing modest capital expenditure directed to the Western
Flank of the Cooper Basin will continue to support production and cash generation for the foreseeable future.

Outlook

The principal focus of the Company’s activities in the coming months will be the advancement of the gas projects as outlined under
‘Business Strategies and Prospects’ above.

Cooper Energy anticipates production from its Cooper Basin operations will range between 0.24 MMbbl to 0.28 MMbbl in FY17.
This compares to a corresponding figure of 0.32 MMbbl in FY16, with the movement reflecting natural field decline in the absence of
drilling activity. Drilling in the Company’s Cooper Basin permits is expected to resume after a 12 month suspension, as part of a program
which is expected to see the drilling of 3 to 5 wells during FY17.

Total capital expenditure will be affected by the FID on Sole. The impact of an affirmative decision is not included in current guidance
of $14 million to $19 million for FY17. Approximately $7 million to $10 million of this estimate is accounted for by the Gippsland Basin gas
projects (exclusive of an affirmative FID).

Direct cash operating costs (production, transport and royalties) of approximately A$31/bbl are anticipated for FY17.

As at 30 June 2016 the Company had oil price hedge arrangements in place for 0.18 MMbbl over 18 months. For FY17, the effect of the
positions taken is that approximately 60% of the Company’s FY17 production is hedged at an average floor price of A$55.98/bbl.

General and administration (G&A) costs are being managed prudently whilst continuing to resource the activities necessary to advance
commercialisation of the Gippsland Basin gas projects and other growth opportunities. G&A costs of approximately $12 million or
approximately $10 million excluding share based payments are anticipated in FY17, which includes approximately $1 million in relation
to Sole project funding (pre FID) and provision for the closure of Tunisian operations.

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
exploration, development and sale of hydrocarbons.

At 30 June 2016 the Company had cash, deposits and investments of $49.8 million. During the first half of 2016, the Group completed
the restructuring of its bank facilities with Westpac Banking Corporation from corporate to reserve-based lending. The facilities have
no debt funding drawn against them and are detailed in Note 7 to the Financial Statements. The Company is advancing implementation of
funding options for its growth projects.

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 performs risk assessments on a regular basis and a summary is reported to the Audit and Risk Committee. The Audit
and Risk Committee approves and oversees an internal audit program, drawing on external industry or field specialists, as appropriate.

Operating and Financial Review
For the year ended 30 June 2016

Risk Management continued

Key risks which may impact the execution and achievement of the business strategies and prospects for Cooper Energy in future financial
years are risks inherent in the oil and gas industry including technical, economic, commercial, operational, environmental and political
risks. This should not be taken to be a complete or exhaustive list of risks. Many of the risks are outside the control of the Company and
its officers.

To help manage these risks, policies and procedures are monitored and updated.

Reconciliations for net loss to Underlying net loss and Underlying EBITDA

Reconciliation to Underlying loss

Net loss after income tax

Adjusted for:

$ million

Impairment of discontinued operations & loss on sale

$ million

Exit provision

Impairment of oil properties

Impairment of exploration and evaluation

Impairment of financial assets AFS

$ million

Accounting gain on acquisition of associate investment

$ million

Realised gain on sale of financial asset HFS

Impairment of investment in associate

Unrealised hedging gain

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

FY16

-34.8

13.0

3.7

0.0

21.7

0.0

0.2

0.0

-6.5

-2.8

FY16

-2.8

-0.8

1.4

-1.2

0.5

4.1

1.2

* Earnings before interest, tax, depreciation and amortisation

Reconciliations of other measures to the Financial Statements

Reconciliation to production volumes

Continuing operations

MMbbl

Add back: Indonesia held for sale / discontinued operations MMbbl

Production volume

Reconciliation to sales volumes

Continuing operations

MMbbl

Add back: Indonesia held for sale / discontinued operations MMbbl

Sales volume

MMbbl

FY16

0.317

0.148

0.465

FY16

0.311

0.140

0.451

0.0

7.5

7.2

7.5

-0.3

-3.6

0.5

0.2

-4.4

-1.3

FY15

-1.3

-1.2

0.5

1.4

0.5

8.2

8.1

FY15

0.400

0.075

0.475

FY15

0.386

0.071

0.457

FY15

-63.5

Change

28.7

47.6

-34.6

3.7

-7.5

14.5

-7.5

0.3

3.6

-0.3

-0.2

-2.1

-1.5

Change

45%

-73%

100%

-100%

201%

-100%

100%

-60%

-100%

-48%

-115%

-1.5

-115%

0.4

0.9

-2.6

0.0

-4.1

-6.9

Change

-0.083

0.073

-0.010

Change

-0.075

0.069

-0.006

33%

180%

-186%

-50%

-85%

-21%

97%

-2%

-19%

97%

-1%

Operating and Financial Review
For the year ended 30 June 2016

Reconciliations of other measures to the Financial Statements continued

Reconciliation to sales revenue

Continuing operations

$ million

Add back: Indonesia held for sale / discontinued operations

$ million

Sales revenue

Reconciliation to average oil price

Continuing operations

$ million

A$/bbl

Add back: Indonesia held for sale / discontinued operations

A$/bbl

Average oil price

Reconciliation to gross profit

Continuing operations

A$/bbl

$ 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

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

Add back: Indonesia held for sale / discontinued operations

$ million

Tax benefit / (expense)

$ million

FY16

20.3

7.2

27.4

FY16

65.27

51.43

60.75

FY15

Change

33.5

5.6

39.1

FY15

86.79

78.87

85.56

-13.2

1.6

-11.7

Change

-21.52

-27.44

-24.81

FY16

FY15

Change

8.1

1.8

9.9

FY16

39.9

25.0

36.1

FY16

9.3

4.1

13.4

13.9

0.2

14.1

-5.8

1.6

-4.2

FY15

Change

41.5

3.6

36.1

-1.6

21.4

0.0

FY15

Change

13.6

3.2

16.8

-4.3

0.9

-3.4

FY16

FY15

Change

2.9

1.2

4.1

FY16

10.8

0.9

11.7

6.0

2.2

8.2

-3.1

-1.0

-4.1

FY15

Change

12.1

0.8

12.9

-1.3

0.1

-1.2

FY16

FY15

Change

7.9

-6.5

-0.2

1.2

3.1

-4.4

-0.1

-1.4

4.8

-2.1

-0.1

2.6

-39%

29%

-30%

-25%

-35%

-29%

-42%

800%

-30%

-4%

594%

-32%

28%

-20%

-52%

-45%

-50%

-11%

13%

-9%

155%

48%

100%

-186%

Directors’ Statutory Report
For the year ended 30 June 2016

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 2016,
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 a member of the Remuneration and Nomination Committee and the Audit and
Risk 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 responsible for the day to day leadership of Cooper Energy. He is the leader of the
management team.

Director’s Statutory Report
For the year ended 30 June 2016

1. Directors continued

Mr Hector M. Gordon
B.Sc. (Hons). FAICD

Executive Director

Appointed 26 June 2012

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 Strait Oil Company Ltd ASX: BAS (since 2014) and various wholly owned
subsidiaries of the Company. He is a former director of ERO Mining Limited (2011 – 2013).

Special Responsibilities

As a part-time executive of the Company, Mr Gordon is responsible for overseeing exploration and
production activities and providing technical expertise in these areas. He is also Chairman of the
HSEC Management Committee and the Indonesian Management 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) and Green Rock
Energy Limited ASX: GRK (2010 – 2013).

Special Responsibilities

Mr Schneider is Chairman of the Remuneration and Nomination Committees and member of the
Audit and Risk 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), Guild Group, Defence Health
and Port of Melbourne Corporation. Ms Williams is a former council member of the Cancer Council
of Victoria.

Special Responsibilities

Ms Williams is Chairman of the Audit and Risk Committee and a member of the Remuneration
and Nomination Committee.

Director’s Statutory Report
For the year ended 30 June 2016

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 has over 20 years’ experience
in finance, treasury, strategy, risk and commercial management, mostly in the construction, energy and resources sectors. Prior to
joining Cooper Energy as CFO he was employed by OZ Minerals as Group Manager Commercial Operations and was previously Group
Commercial Manager and Treasurer with the Futuris/Elders Group.

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 AO

Mr D. Maxwell

Mr H. Gordon

Mr J. Schneider

Ms A. Williams

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

4. Remuneration Report

Information about the remuneration of the Company’s key management personnel for the financial year ended 30 June 2016 is set out in
the Remuneration Report.

The information in this Report has been audited as required by the Corporations Act 2001 (Cth) and forms part of the Directors’ Report.

4.1 Remuneration Overview

The impact of, and response to, lower oil prices has been a focus of the Company during the reporting period. The Directors have ensured
that the Company’s overall remuneration philosophy has been followed so that remuneration maintains alignment with shareholder
interest, remains market competitive and continues to provide significant incentive to deliver superior performance as the Company
delivers on its strategic goals, in particular to build its gas business.

Key Highlights for Remuneration in FY16

The Company implemented various initiatives to reduce costs in the lower oil price environment including employment costs. These
included some employees agreeing to reduce their working hours and not filling some vacant positions while the Company undertook a
review of its human resources needs as it advanced its Gippsland Basin gas projects in the later part of the reporting period.

In recognition of the lower oil price environment and to support employees in their efforts to reduce costs, the non-executive directors also
reduced their directors’ fees by 10% from 1 December 2015.

Shareholders approved a new Equity Incentive Plan (EIP) at the 2015 AGM to better align the Company’s long-term incentive plan with
its current strategy, objectives and current peer group market practice. The EIP was implemented during the reporting period. Key
features of the long-term incentive arrangements are set out in the table on page 43.

Director’s Statutory Report
For the year ended 30 June 2016

4. Remuneration Report (Audited) continued

4.1 Remuneration Overview continued

Remuneration actually delivered to Executives for FY16 (not audited)

The Company believes that reporting remuneration actually delivered to Executives is useful to shareholders and provides clear and
transparent disclosure of remuneration provided by the Company. The following table shows remuneration actually delivered to the
Executives during the reporting period. This information is non-IFRS and is in addition to and different from the disclosures required by
the Corporations Act and Accounting Standards, in the rest of the Remuneration Report and the tables in sections 4.14 and 4.15,
and is not audited.

Name

Executive Directors

Mr D. Maxwell

Mr H. Gordon5

Executives

Mr A. Thomas

Mr J. de Ross

Ms A. Evans6

Mr I. MacDougall

Mr E. Glavas

Year

Fixed
Remuneration1
$

STIP2

LTIP3

Other4

Total

2016

2015

2016

2015

2016

2015

2016

2015

2016

2015

2016

2015

2016

2015

650,000

275,000

645,000

219,502

223,736

375,123

396,408

335,276

351,719

176,089

187,024

382,025

379,019

281,190

241,902

422,100

80,500

180,370

96,000

112,283

85,000

110,559

47,500

55,989

87,000

48,277

62,000

5,000

93,907

465,480

51,922

78,681

28,433

9,419

83,349

1,102,256

82,810

1,615,390

6,373

6,134

5,824

6,248

6,373

6,025

6,236

6,025

6,419

6,114

6,373

5,112

358,297

410,240

555,628

514,939

455,082

468,303

239,244

249,038

475,444

433,410

349,563

252,014

1. ‘Fixed Remuneration’ comprises base salary and superannuation.

2. ‘STIP’ is the amount of the STIP cash bonus that was actually paid to the Executive during the 2016 financial year in respect of

performance in the 2015 financial year. For the value of the STIP calculated in accordance with the Accounting Standards, see the
tables in Section 4.14 and Section 4.15.

3. The figures in this ‘LTIP’ column show the pre-tax value of performance rights which vested during the reporting period, calculated
based on the share price on the date the performance rights were vested. For the value of the LTIP calculated in accordance with
the Accounting Standards, see the tables in Section 4.14 and Section 4.15.

4. ‘Other’ short-term benefits include fringe benefits on accommodation, car parking and other benefits.

5. Mr Gordon works part-time (0.5 full time equivalent) and accordingly his entitlements are prorated.

6. Ms Evans works part-time (0.7 full time equivalent for 4 months and 0.6 full time equivalent for 8 months) and accordingly her

entitlements are prorated.

Key Developments for Remuneration in FY17

Cooper Energy employees who have the opportunity to participate in the EIP (being key management personnel and other senior
technical staff) have agreed to a 10% reduction to their annual base salaries commencing from 1 July 2016.

Staff who no longer participate in the long-term incentive scheme will be issued performance rights as deferred STIP for the first time
in accordance with the changes to the long-term incentive plan implemented during the reporting period.

Director’s Statutory Report
For the year ended 30 June 2016

4. Remuneration Report (Audited) continued

4.2 Key Management Personnel (KMP)

The following were KMP of the Group during the whole of the reporting period:

Non-Executive Directors

Mr J. Conde AO (Chairman)

Executive Directors

Mr D. Maxwell (Managing Director)

Mr J. Schneider

Ms A. Williams

Executives

Mr H. Gordon (Executive Director Production and Exploration)

Mr J. de Ross (Chief Financial Officer and Company Secretary)

Ms A. Evans (Company Secretary and Legal Counsel)

Mr A. Thomas (Exploration Manager)

Mr I. MacDougall (Operations Manager)

Mr E. Glavas (Commercial and Business Development Manager)

4.3 Remuneration Philosophy and Objectives

The Company is committed to a remuneration philosophy that rewards consistent and sustainable individual performance and
superior corporate performance.

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 KMP.

It is the Company’s policy to pay fixed remuneration at the median level of the market for the oil and gas sector and supplement this
with the opportunity to earn performance based remuneration. This is intended to bring the overall total remuneration package to
the upper quartile of the market only when top level performance is achieved.

4.4 Remuneration Framework

Remuneration for Non-Executive Directors consists of Directors’ fees and statutory superannuation only, and for employees
(including Executive Directors) consists of base salary, statutory superannuation, short-term incentives, other short-term benefits and
long term incentives.

Remuneration is determined by reference to market conditions and comparisons (e.g. benchmark reports). It is determined in
conjunction with an annual review of the performance of Executive Directors, Executives and other employees of the Company.
Performance of the Directors of the Company, including the Managing Director, is evaluated by the Board, who may be assisted by
the Remuneration & Nomination Committee. The Managing Director reviews the performance of Executives with the assistance of the
Remuneration & Nomination Committee. These evaluations take into account criteria such as the contribution toward the Company’s
performance benchmarks and the achievement of individual performance objectives.

During the reporting period, the Board obtained and used independent Australian hydrocarbon industry remuneration data to
benchmark remuneration rates for all employees (see also Section 4.10).

Director’s Statutory Report
For the year ended 30 June 2016

4. Remuneration Report (Audited) continued

4.5 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 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 Executives.

4.6 Nature and amount 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.

Remuneration paid to the Non-Executive Directors was reduced by 10% from 1 December 2015, by agreement of the Non-Executive
Directors in recognition of the lower oil price environment and the changes that staff were making to their own work arrangements.
Remuneration paid to the Non-Executive Directors for the reporting period and for the previous reporting period is shown in the table in
Section 4.14.

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.

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.

4.7 Nature and amount of Executive (including Executive Director) remuneration

Executive remuneration during the reporting period consisted of:

• base salary including statutory superannuation;

• short-term incentive plan (being performance based cash bonuses);

• other short-term benefits; and

• long-term incentive plan (currently comprising the award of performance rights and share appreciation rights under the Company’s

Equity Incentive Plan (EIP)).

Remuneration payable to the Executive Directors, and the Executives, for the reporting period, and for the previous reporting period, is
shown in the tables in Sections 4.14 and 4.15 in accordance with the Corporations Act and Accounting Standards, and each of the above
remuneration components is discussed further below.

Fixed Remuneration - Base salary and superannuation

Base salary is paid in cash and is not at risk (other than by termination). The Company pays statutory superannuation contributions on
behalf of the Executives.

Executives are paid base salaries which are competitive in the markets in which the Company operates and consistent with the
remuneration philosophy. Individual base salary is set each year based on job description, competitive market salary information sourced
by the Company and overall competence of the Executive in fulfilling the requirements of the particular role.

The Company benchmarks Executive 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.

The Company’s base salary review process is performed annually and takes into consideration factors such as market benchmark
changes, changes in individual responsibility, individual performance, the performance of the Company and relevant economic indicators.
Overall changes will typically reflect market benchmark changes, with individual changes varying according to an assessment of individual
performance and responsibilities.

Director’s Statutory Report
For the year ended 30 June 2016

4. Remuneration Report (Audited) continued

4.7 Nature and amount of Executive (including Executive Director) remuneration continued

Short-term incentive plan (STIP)

The short-term incentive plan (STIP) award is made by way of a cash bonus.

All performance criteria under the STIP are relevant to the Company’s strategic objectives and designed to incentivise Executives to meet
goals which enhance shareholder value. Performance criteria are challenging and maximum award opportunities are only achieved by
outstanding performance. Each year the Board reviews and approves the performance criteria for the year ahead.

The maximum short-term incentive award opportunities for Executives are as follows:

Position

Managing Director

Executive Director

Executives

Maximum opportunity as percentage of base salary (including
superannuation)

100%

75%

50%

The relative weighting of Company and individual performance varies dependant on the level of the Executive and is as follows:

Position

Managing Director

Executive Director

Executives

Company Performance

Individual Performance

80%

75%

70%

20%

25%

30%

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 Company strategy and maximise
sustainable shareholder returns. Personal performance is measured against performance criteria agreed between the Executive and
Cooper Energy each year.

In the financial year 2016, the scorecard KPIs and their relative weightings were as follows:

STIP Key Performance Indicators

HSEC performance

Increased production from existing permits

Growth in reserves and resources

Key gas strategy milestones

Acquisitions and divestments

Cost management

Processes and risk management

Relationships – external and internal

Funding

Rationale for choosing KPI

Care is a core value for Cooper Energy - prioritising safety,
health the environment and community.

Oil production generates cash flow for the Company
which underpins its other activities.

Growth in oil and gas reserves and production are at the
heart of Cooper Energy’s business. Growth in Cooper
Energy’s gas portfolio is a key element of the Company’s
eastern States gas strategy.

These are enablers to support the Company’s other key
drivers in an efficient and cost effective way. By including
risk management KPIs, it is made clear to employees that
excessive risk taking is not rewarded or encouraged when
pursuing incentive awards.

Director’s Statutory Report
For the year ended 30 June 2016

4. Remuneration Report (Audited) continued

4.7 Nature and amount of Executive (including Executive Director) remuneration continued

For each KPI in the scorecard, a base or threshold performance level is established the measure for which will be articulated in the
scorecard as well as a target, stretch target and super stretch target performance level. The measures will be set in accordance with the
following objectives:

Threshold

Measure

STIP Award as % of
maximum opportunity

Base

Target

Stretch

Super stretch

Level of performance that is expected to be achieved and is
nearly at target level

This is a challenging and achievable level of performance

Excellent performance - doing better than target and consistent
with leading peers

Outstanding performance - doing better than, or best in class,
when compared to peers

100

The Board assesses performance against the scorecard each year. Average weighted performance of the total scorecard is the sum of the
performance assessed for each item multiplied by the weighting for each item.

STIP payments, if any, are made in October each year. Therefore any STIP payments for the year ended 30 June 2016 will be paid in
October 2016. Irrespective of the scorecard outcome, payment of any STIP is entirely at the discretion of the Board.

STIP payments made to Executive Directors, and Executives, during the reporting period, and during the previous reporting period, are
shown in the tables in Sections 4.14 and 4.15 in accordance with the Corporations Act and Accounting Standards.

Other short-term benefits

Other short-term benefits for Executives include fringe benefits on car parking, accommodation and other benefits as set out in the table in
Section 4.15.

Long-term incentive plan

The Company believes that encouraging its employees, including Executives, 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).

In this 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. Prior to 2015, the LTIP
involved awards of performance rights made under the long-term incentive plan which was in operation since 2011 (2011 Plan).
The key features of each plan are set out in the following table:

Director’s Statutory Report
For the year ended 30 June 2016

4. Remuneration Report (Audited) continued

4.7 Nature and amount of Executive (including Executive Director) remuneration continued

Plan Feature

Vehicle

2011 Plan

Performance Rights

EIP

A combination of Performance Rights, Share
Appreciation Rights (SARs) and/or Options (as
determined by the board).3

Rationale: This gives the Board flexibility to use the
vehicle appropriate to the Company’s objectives at the
time of grant. The Board issued 50% SARs and 50%
Performance Rights in 2015.

Maximum award opportunity
for Executives (% of fixed
annual remuneration)

Managing Director

Executive Director

Executives

120%

95%

70%

Managing Director

Executive Director

Executives

Senior technical employee 50%

Senior employees

120%

95%

70%

50%

Performance Period

Staff

33% 1 year

33% 2 years

33% 3 years

Vesting Period

3 years

30%

Staff do not participate in long-term incentive plan.

100% 3 - 4 years (3 years plus 1 retest at
4 years – see below).

Rationale: A longer measurement period reflects the
Company’s desire to create consistent and sustained
shareholder returns over the measurement period.

3 – 4 years (3 years plus 1 retest at 4 years
– see below).

Performance measures
(Non-market)

Performance Measures (Market)
and Vesting criteria

None (incorporated in STIP)

25% Absolute TSR

< 5% zero vests

=5% 25% vests

=15% 50% vests

> 25% 100% vests

75% Relative TSR

Ranked out of 9:

Rank <5 zero vests

Rank 5, 50% vests

0% Absolute TSR however no SARs will be exercisable
unless the share price appreciates over the
measurement period.

100% Relative TSR

<50th percentile = 0% vesting

= 50th percentile = 30% vesting

>50th percentile and < 90th percentile

Rank 3 or 4, partial vesting

= prorata vesting

Rank 1 or 2, 100% vests

= or >90th percentile = 100% vesting

(this is equivalent to 75th percentile
100% vests)

Rationale: Absolute shareholder returns measures can
be influenced by factors over which the Company has
no control such as the volatility in oil price. Relative
measures ensure that maximum incentives are only
achieved if Cooper Energy’s performance exceeds that
of its peers.

3 Performance right – a right granted for nil consideration which, on vesting, will result in the employee being entitled to one share in

the Company (for nil consideration) or the cash equivalent.

Share Appreciation Right (SAR) – a right granted for nil consideration which, on vesting, will result in the employee being entitled
to an amount equal to the difference in value in the Company share price between the grant date and vesting date, settled in cash or
shares in the Company (for nil consideration).

Option – a right granted for nil consideration which, on vesting and subject to exercise of the option (including payment of any

applicable exercise price), will result in the employee being entitled to one share in the Company for each option exercised (for nil
consideration) or the cash equivalent.

Director’s Statutory Report
For the year ended 30 June 2016

4. Remuneration Report (Audited) continued

4.7 Nature and amount of Executive (including Executive Director) remuneration continued

Plan Feature

2011 Plan

EIP

Relative TSR peer group

8 peer group companies: Beach Energy
Limited; Senex Energy Limited; Drillsearch
Energy Limited; Tap Oil Limited; Cue Energy
Resources Limited; Central Petroleum
Limited, AWE Limited and Icon Energy
Limited.

12 peer group companies: 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.

Re-testing

Annually following initial test up until
3 years.

Rationale: Comparable peers for Cooper Energy are
limited, however independent advice to the Company
was that an extended peer group is more appropriate.

1 retest only 12 months after original 3 year test date.

Rationale: A retest has been retained but in the
context of a longer measurement and vesting period.
A retest is considered to be justified because the
Company’s growth is dependent on development of
projects that will likely take greater than 3 years from
conception to start-up.

Vesting

Clawback

Vesting to the extent applicable after
performance criteria are met.

Vesting to the extent applicable after performance
criteria are met.

Any unvested rights will not vest if the Board
determines that the employee has acted
fraudulently, dishonestly or in breach of the
employee’s obligations.

Any unvested rights will not vest if the Board
determines that the employee has acted fraudulently,
dishonestly or in breach of the employee’s obligations.

Grant frequency

Annual.

Change of control provisions

Board discretion.

Prorata vesting based on service and performance.

Eligibility to participate

All employees.

Management and senior staff

Rationale: Decisions regarding longer term Company
growth are more relevant for management and senior
employees. Staff taken out of the LTIP will be given
the opportunity to become shareholders by receiving
a deferred component of a STIP which will be paid
in equity.

Dilution caps

2% for each tranche.

5% total on issue (excluding KMP).

Rationale: 5% is the required threshold under ASIC
Class Order disclosure relief relating to employee
incentive schemes.

4.8 Relationship between remuneration framework and Company performance

The Company’s remuneration policy seeks to encourage alignment between the performance of the Company and the remuneration of
Executives.

It is the Company’s policy that the performance based (or at risk) pay of Executives forms a significant portion of their total remuneration.
In addition, within performance based pay, an appropriate balance is targeted between rewarding long-term sustainable performance
(through the long-term incentive plan) and rewarding operational performance (through the short-term incentive cash bonuses).

The oil and gas industry is a specialised industry in which highly skilled workers are usually both mobile and highly sought after in
Australia and overseas. The Company competes for talent with much larger organisations, often able to pay higher base salaries. It is
important that the Company attracts people motivated and aligned to doing all they can to deliver top level performance whilst being
mindful of effective employee cost management. In order to attract, motivate, reward and retain the right employees, it is the Company’s
policy to pay fixed remuneration at the median level of the market, and supplement this with the opportunity to earn performance based
remuneration to bring the overall total remuneration package to the upper quartile level of the market only when top level performance
is achieved.

Director’s Statutory Report
For the year ended 30 June 2016

4. Remuneration Report (Audited) continued

4.8 Relationship between remuneration framework and Company performance continued

The Company’s remuneration profile for Executives 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

Base

STIP

LTIP4

Total

Managing
Director

Executive
Director

Executives

Managing
Director

Executive
Director

Executives

100%

50%

120%

270%

100%

38%

95%

233%

100%

25%

70%

195%

100%

120%

320%

100%

75%

95%

270%

100%

50%

70%

220%

Company performance – STIP and 2011 Plan results

For the reporting period to 30 June 2016, the Company’s performance was measured against Company KPIs which were set out in a
scorecard and weighted (as described in Section 4.7 above). The preliminary scorecard results indicate that the Company met or exceeded a
number of its STIP KPIs but did not meet others:

STIP KPIs

2016 Financial Year Performance

Comment

HSEC Performance

Super Stretch

Increased production from
existing assets

Below Base

Growth in reserves
and resources

Key gas strategy milestones

Target

Acquisitions and divestments

Cost management

Processes and
Risk Management

Stakeholder Relationships

Stretch

0.0 Total Recordable Case Frequency Rate and a 0.0 Lost Time
Injury Frequency Rate over the 2016 Financial Year. This is an
excellent result and much better than industry benchmarks.
Environmental and community targets were also exceeded.

The lower oil price environment resulted in no drilling being
undertaken and therefore total production was not increased
from existing assets.

Good progress was made in each of the key areas, particularly
in relation to the Gippsland Basin gas projects. The Company
increased its contingent and prospective resources, secured
Heads of Agreement for gas sales and is near to completing
FEED for development of the Sole gas project. The Company is
on target to divest the international assets.

Diligent management of costs and the oversubscribed capital-
raising significantly improved the financial position of the
Company. The Company’s processes have proven to be fit for
purpose and staff are genuinely engaged and committed to
safely delivering on our strategy.

The overall performance will be assessed by the Board. The score, in conjunction with individual performance reviews, will form the basis
of individual STIP payments in October 2016.

As described in Section 4.7 above, the LTIP aligns the rewards received by participants with the longer term performance of the Company
including by measuring the total shareholder returns against that of its peers.

4 Reflects LTIP granted however may not necessarily reflect the amount that will ultimately vest and be exercised.

Director’s Statutory Report
For the year ended 30 June 2016

4. Remuneration Report (Audited) continued

4.8 Relationship between remuneration framework and Company performance continued

The Company’s absolute shareholder return and relative shareholder return for the vesting period for performance rights granted on 2
August 2012 (2012 Award (1)), 10 December 2012 (2012 Award (2)) and 1 May 2013 (2013 Award) were tested for the final time during
the reporting period in accordance with the 2011 Plan rules. The results for the period are as follows:

Number Performance
Rights Vested

Number Performance
Rights Cancelled

% vested over 3 year
measurement period

180,553

1,588,437

66,902

72,427

3,583,905

200,705

2012 Award (1)

2012 Award (2)

2013 Award

4.9 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 now end on 10 October 2017.

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. The initial
term of Mr Gordon’s contract expired on 24 June 2015 and was renewed to now end on 24 June 2017. From 1 March 2014, Mr Gordon’s
role has been part-time (0.5 full time equivalent). Mr Gordon continues to provide oversight of the exploration and production business.

Mr Gordon or the Company may terminate the contract by providing six months’ written notice or payment in lieu of notice. The Company
may also terminate the contract immediately for cause.

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.

Executives

The Company has entered into a contract of employment with each Executive. 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.

4.10 External remuneration advisers

During the reporting period, the Remuneration & Nomination Committee engaged Strategic Human Resources Pty Ltd (SHR) to
benchmark salaries for all employees, including Executives. This involved the review and application of remuneration data sourced
from National Rewards Group Inc. Fees payable to SHR for services to 30 June 2016 totalled $3,790. Annual membership fees payable
to National Rewards Group were $4,785.

In addition, the Remuneration & Nomination Committee engaged Guerdon Associates to provide advice to the Board regarding the
Company’s new equity incentive plan. Fees payable to Guerdon Associates for services to 30 June 2016 totalled $9,867.

The Board is satisfied that all remuneration advice received was provided free from undue influence by any KMP to whom the
advice related.

4.11 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 28 September 2015. 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).

Director’s Statutory Report
For the year ended 30 June 2016

4. Remuneration Report (Audited) continued

4.11 Accounting for performance rights continued

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
reporting
period

Fair
value of
rights at
grant
date

No. of
rights
vested
during
reporting
period

% of
rights
vested
to 30
June
2016

No. of
rights
granted
during
reporting
period

Fair
value of
rights at
grant
date

No. of
rights
vested
during
reporting
period

% of
rights
vested
to 30
June
2016

No. of
rights
granted
during
reporting
period

Fair
value of
rights at
grant
date

No. of
rights
vested
during
reporting
period

% of
rights
vested
to 30
June
2016

Executive
Directors

Mr D. Maxwell

Mr H. Gordon

Executives

Mr A. Thomas

Mr J. de Ross

Ms A. Evans

Mr I. MacDougall

Mr E. Glavas

Nil

494,247

2,228,571 $291,943

273,274

645,810

$84,601

347,590

149,647

38,446

Nil

796,722 $104,371

709,017

$92,881

383,370

$50,221

764,050 $100,091

567,810

$74,387

Nil

6,290,332 $390,000

1,822,850 $113,017

2,248,812 $139,426

2,001,259 $124,078

1,082,094

$67,090

2,156,592 $133,709

1,602,774

$99,372

Nil

The vesting date of the performance rights granted on 15 December 2015 is 14 December 2019. The fair value of these rights is $0.131
per right. These performance rights have a commencement date of 28 September 2015.

The vesting date of the share appreciation rights granted on 15 December 2015 is 14 December 2019. The fair value of these rights is
$0.062 per right. These share appreciation rights have a commencement date of 28 September 2015.

4.12 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 2015

Granted

Lapsed

Vested &
Exercised

Held at
30 June 2016

Directors

Mr D. Maxwell

Mr H. Gordon

Executives

Mr A. Thomas

Mr J. de Ross

Ms A. Evans

Mr I. MacDougall

Mr E. Glavas

4,231,293

1,998,817

1,745,957

1,325,582

629,211

808,722

338,039

823,745

455,457

350,822

249,412

115,336

494,247

273,274

347,590

149,647

38,446

2,913,301

1,270,086

1,047,545

926,523

475,429

808,722

338,039

The performance rights lapsed during the period noted in the table above were granted in July 2012, December 2012 and May 2013.

Director’s Statutory Report
For the year ended 30 June 2016

4. Remuneration Report (Audited) continued

4.12 Additional remuneration disclosures continued

Held at
1 July 2014

Granted

Lapsed

Vested &
Exercised

Held at
30 June 2015

4,430,269

1,578,992

1,228,028

864,668

389,577

312,033

1,448,737

419,825

517,929

460,914

239,634

496,689

338,039

164,001

1,483,712

4,231,293

1,998,817

1,745,957

1,325,582

629,211

808,722

338,039

Held at
1 July 2015

Granted

Lapsed

Vested &
Exercised

Held at
30 June 2016

2,228,571

645,810

796,722

709,017

383,370

764,050

567,840

2,228,571

645,810

796,722

709,017

383,370

764,050

567,840

Held at
1 July 2015

Granted

Lapsed

Vested &
Exercised

Held at
30 June 2016

6,290,332

1,822,850

2,248,812

2,001,259

1,082,094

2,156,592

1,602,774

6,290,332

1,822,850

2,248,812

2,001,259

1,082,094

2,156,592

1,602,774

Performance Rights
(2011 Plan)

Executive Directors

Mr D. Maxwell

Mr H. Gordon

Executives

Mr A. Thomas

Mr J. de Ross

Ms A. Evans

Mr I. MacDougall

Mr E. Glavas

Performance Rights
(EIP)

Executive Directors

Mr D. Maxwell

Mr H. Gordon

Executives

Mr A. Thomas

Mr J. de Ross

Ms A. Evans

Mr I. MacDougall

Mr E. Glavas

Share Appreciation
Rights (EIP)

Executive Directors

Mr D. Maxwell

Mr H. Gordon

Executives

Mr A. Thomas

Mr J. de Ross

Ms A. Evans

Mr I. MacDougall

Mr E. Glavas

Director’s Statutory Report
For the year ended 30 June 2016

4. Remuneration Report (Audited) continued

4.12 Additional remuneration disclosures continued

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 2015

Purchases

Received on vesting
of performance rights

Sales

Held at
30 June 2016

Directors

Mr J. Conde AO

Mr D. Maxwell

Mr H. Gordon

Mr J. Schneider

Ms A. Williams

Executives

Mr J. de Ross

Mr A. Thomas

Ms A Evans

Directors

Mr J. Conde AO

Mr D. Maxwell

Mr H. Gordon

Mr J. Schneider

Ms A. Williams

Executives

Mr J. de Ross

4.13 Options

250,000

2,746,902

173,608

300,000

30,000

200,000

22,728

68,184

22,728

13,637

22,728

494,247

273,274

149,647

347,590

38,446

272,728

3,309,333

469,610

322,728

52,728

372,375

361,227

61,174

Held at
1 July 2014

Purchases

Received on vesting
of performance rights

Sales

Held at
30 June 2015

250,000

1,263,190

173,608

300,000

30,000

200,000

1,483,712

250,000

2,746,902

173,608

300,000

30,000

200,000

No options were issued (or forfeited) during the year.

Director’s Statutory Report
For the year ended 30 June 2016

4. Remuneration Report (Audited) continued

4.14 Table of Directors’ remuneration for 2015 and 2016 financial years

Base
Salary &
Fees

Directors

Mr J. Conde AO

2016

137,595

2015

146,119

2016

81,697

2015

86,758

Benefits

Short-term

STIP

Other
Short-term
Benefits(a)

Appointed as
Chairman on
25/02/13

Mr J. Schneider

Appointed as Non-
Executive Director
on 12/10/11

Mr D. Maxwell

Appointed as
Managing Director
on 12/10/11

Mr H. Gordon

Appointed as
Executive Director on
26/06/12 (0.5 FTE
from 01/03/14)

Ms A. Williams

Appointed as Non-
Executive Director
on 28/08/13

2016

630,692 342,388

83,350

2015

626,217

509,713

82,810

2016

200,194

93,997

6,373

2015

204,953

139,901

6,134

2016

81,697

2015

86,758

Long
Term

Long
Service
Leave

Post
Employment

Share Based
Payment(c)

Superannuation(b)

LTIP

Total

13,072

13,881

7,761

8,242

19,308

18,783

19,308

150,667

160,000

89,458

95,000

517,092

1,592,830

491,800

1,729,323

220,606

540,478

18,783

215,518

585,289

7,761

8,242

89,458

95,000

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.

Director’s Statutory Report
For the year ended 30 June 2016

4. Remuneration Report (Audited) continued

4.15 Table of Executives’ remuneration for 2015 and 2016 financial years

Benefits

Short-term

Base Salary

STIP

Long
Term

Post
Employment

Share Based
Remuneration(c)

Other
Short-term
Benefits (a)

Long
Service
Leave

Superannuation(b)

LTIP

Total

2016

355,815

98,798

5,824

2015

377,625

153,256

6,248

2016

315,968

87,922

6,373

2015

332,936

135,551

6,025

2016

156,781

46,278

6,236

2015

168,241

67,961

6,025

2016

362,717

100,616

6,419

2015

360,236

146,660

6,114

2016

261,882

74,777

6,373

2015

224,684

97,799

5,112

19,308

186,377

666,122

18,783

179,910

735,822

19,308

162,930

592,501

18,783

126,734

620,029

19,308

81,046

309,649

18,783

46,326

307,336

19,308

128,013

617,073

18,783

56,180

587,973

19,308

65,299

427,639

17,218

12,752

357,565

Executives

Mr A. Thomas

Commenced as
Exploration Manager
on 01/07/12

Mr J. de Ross

Commenced as Chief
Finance Officer on
27/09/12 and as
Company Secretary
on 25/11/13

Ms A. Evans

Commenced as
Company Secretary
and Legal Counsel
(0.7 FTE ) on
21/02/13

Mr I. MacDougall

Commenced as
Operations Manager
02/02/14

Mr E. Glavas

Commenced
as Commercial
and Business
Development
Manager 04/08/14

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

End of remuneration report.

Director’s Statutory Report
For the year ended 30 June 2016

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.

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 report 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

272,728

3,309,333

469,610

322,728

52,728

5,141,872

1,915,896

6,290,322

1,822,850

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 11,167,070 outstanding performance rights granted to employees under the 2011 Plan and 7,892,812
outstanding performance rights and 22,278,100 share appreciation rights under the Equity Incentive Plan approved by shareholders at
the 2015 AGM.

During the financial year 2,234,300 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 2016.

12. Events after financial reporting date

Refer to Note 31 of the Notes to the Financial Statements.

Director’s Statutory Report
For the year ended 30 June 2016

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.

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 109 and forms part of the Directors’ report for the financial year ended
30 June 2016.

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
$18,540 (2015: $nil).

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 15 August 2016

Financial Statements

For the year ended 30 June 2016

Consolidated Statement of Comprehensive Income
For the year ended 30 June 2016

Continuing Operations

Revenue from oil sales

Cost of sales

Gross profit

Other revenue

Exploration and evaluation expenditure written back /(off)

Finance costs

Impairment

Reclassification of fair value movement on sale of available for sale investments

Share of loss in associate

Other expenses

Loss before tax

Income tax benefit

Total tax benefit

Consolidated

2016
$’000

2015
$’000

Notes

20,257

33,510

(12,180)

(19,589)

8,077

13,921

850

292

(1,392)

1,867

(2,342)

(495)

(21,865)

(22,642)

(87)

(11,870)

(25,995)

7,907

3,634

(166)

(12,002)

(18,225)

3,089

Net loss after tax from continuing operations

(18,088)

(15,136)

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

Fair value movements on available for sale investments

(16,751)

(34,839)

(48,332)

(63,468)

237

(3,526)

2,526

300

1,059

(8,325)

1,346

7,471

(3,634)

Income tax effect on fair value movements on available for sale financial assets

Reclassification during the year to profit or loss of impairment loss on available for sale investments

Reclassification during the year to profit or loss of profit on sale of available for sale investments

Fair value movements on derivatives accounted for in a hedge relationship

Reclassification during the period to profit or loss of realised hedge settlements

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

(553)

Other comprehensive expenditure for the period net of tax

(1,016)

(2,083)

Total comprehensive loss for the period attributable to members

(35,855)

(65,551)

Basic earnings per share from continuing operations

Diluted earnings per share from continuing operations

Basic earnings per share

Diluted earnings per share

cents

(5.3)

(10.1)

cents

(4.6)

(19.2)

The above Statement of Comprehensive Income should be read in conjunction with the accompanying notes.

Consolidated Statement of Financial Position
As at 30 June 2016

Consolidated

2016
$’000

2015
$’000

Notes

Assets

Current Assets

Cash and cash equivalents

Trade and other receivables

Inventory

Income tax receivable

Prepayments

Assets classified as held for sale

Total Current Assets

Non-Current Assets

Available for sale financial assets

Equity instruments at fair value through other comprehensive income

Investment in associate

Term deposits at banks

Oil properties

Property, plant & 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

Provisions

Financial liabilities

Total Non-Current Liabilities

Total Liabilities

Net Assets

Equity

Contributed equity

Reserves

Accumulated losses

Total Equity

The above Statement of Financial Position should be read in conjunction with the accompanying notes.

49,717

3,400

303

53,420

4,788

58,208

790

173

5,385

708

39,373

12,001

940

859

640

53,813

1,343

520

11,921

981

110,976

105,363

118,123

120,187

176,331

174,000

8,014

4,064

1,275

8,936

1,913

13,353

10,849

645

13,998

10,849

2,176

65,548

3,059

70,783

11,020

45,194

3,066

59,280

84,781

70,129

91,550

103,871

137,558

115,460

6,571

6,151

(52,579)

(17,740)

91,550

103,871

Consolidated Statement of Changes in Equity
For the year ended 30 June 2016

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

Balance at 1 July 2014

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

Balance at 30 June 2015

Issued Capital

Reserves

(Accumulated
Losses) /
Retained
Earnings

Total
Equity

$’000

115,460

6,151

(17,740)

103,871

448

21,650

137,558

114,625

835

115,460

(34,839)

(1,016)

(34,839)

(35,855)

1,884

(448)

6,571

7,440

(2,083)

1,629

(835)

6,151

(52,579)

1,884

21,650

91,550

45,728

167,793

(63,468)

(2,083)

(63,468)

(65,551)

1,629

(17,740)

103,871

The above Statement of Changes in Equity should be read in conjunction with the accompanying notes.

Consolidated Statement of Cash Flows
For the year ended 30 June 2016

Cash Flows from Operating Activities

Receipts from customers

Payments to suppliers and employees

Income tax received / (paid)

Interest received

Net cash from operating activities

Cash Flows from Investing Activities

Transfers of term deposits

Receipts from sale of subsidiary

Payment for acquisition of investment in associate

Receipts from sale of financial assets

Payments for exploration and evaluation

Acquisition of exploration and evaluation

Investments in oil properties

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

The above Statement of Cash Flows should be read in conjunction with the accompanying notes.

Consolidated

2016
$’000

2015
$’000

Notes

28,078

38,613

(21,851)

(33,065)

859

849

7,935

(5,062)

1,549

2,035

(32)

1,860

12,440

(273)

15,660

(28,910)

(13,189)

(3,486)

(4,470)

(9,763)

(19,988)

(10,175)

21,171

9,118

1,226

39,373

49,717

(8,140)

335

47,178

39,373

1. Corporate information

The consolidated financial report of Cooper Energy Limited (the parent entity) for the year ended 30 June 2016 was authorised for issue in
accordance with a resolution of the Directors on 15 August 2016.

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 which have been measured at fair value. Cooper Energy Limited is a for profit company.

The financial report is presented in Australian dollars and all values are rounded to the nearest thousand dollars ($’000) unless otherwise
stated under the option available to the Group under ASIC Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191.
The Group is an entity to which the legislative instrument applies.

Significant event and transaction

During the period the Group raised additional equity through an institutional placement and a share purchase plan. As a result of the
institutional placement, 83.4 million new shares were issued; a further 17.6 million shares were issued under the share purchase plan.
A total of $21.7 million (net of costs and tax) was raised from the two transactions. Refer to Note 21 for further information.

During the period, the Group’s Asian and African operations were classified as discontinued operations. Refer to Note 12 for further
information.

During the period the Group’s interest in VIC/RL 13-15 increased to 100% after Beach Energy assigned its 35% interest in the permits
to the Group. This resulted in an increase to the restoration provision and a corresponding increase to exploration and evaluation assets.
Refer to Notes 17 and 19 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

The Accounting policies adopted are consistent with those of the previous financial year except as follows:

The Group has adopted the following new and amended Australian Accounting Standard and AASB Interpretations as of 1 July 2015:

• AASB 2012-3 Amendments to Australian Accounting Standards arising from the Withdrawal of AASB 1031 Materiality

• AASB 9 Financial Instruments

Adoption of these standard interpretations is described below:

Notes to the Financial StatementFor the year ended 30 June 20162. Summary of significant accounting policies continued

b) Statement of compliance continued

AASB 2015-3

Summary

Amendments to Australian Accounting Standards arising from the Withdrawal of AASB 1031
Materiality

The Standard completes the AASB’s project to remove Australian guidance on materiality from
Australian Accounting Standards.

Application Date of the Standard

1 July 2015

Application Date for Group

1 July 2015

Impact on Group Financial report The application of this standard has not resulted in any significant change in the 2016 year

AASB 9

Summary

end accounts.

Financial Instruments

AASB 9 (December 2014) is a new standard which replaces AASB 139. 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.

AASB 9 is effective for annual periods beginning on or after 1 January 2018. However, the
Standard is available for early adoption. The own credit changes can be early adopted in isolation
without otherwise changing the accounting for financial instruments.

Classification and measurement

AASB 9 includes requirements for a simpler approach for classification and measurement of
financial assets compared with the requirements of AASB 139. There are also some changes
made in relation to financial liabilities.

The main changes are described below.

Financial assets

a. Financial assets that are debt instruments will be classified based on (1) the objective of the
entity’s business model for managing the financial assets; (2) the characteristics of the
contractual cash flows.

b. Allows an irrevocable election on initial recognition to present gains and losses on investments
in equity instruments that are not held for trading in other comprehensive income. Dividends in
respect of these investments that are a return on investment can be recognised in profit or loss
and there is no impairment or recycling on disposal of the instrument.

c. Financial assets can be designated and measured at fair value through profit or loss at initial
recognition if doing so eliminates or significantly reduces a measurement or recognition
inconsistency that would arise from measuring assets or liabilities, or recognising the gains and
losses on them, on different bases.

Financial liabilities

Changes introduced by AASB 9 in respect of financial liabilities are limited to the measurement of
liabilities designated at fair value through profit or loss (FVPL) using the fair value option.

Where the fair value option is used for financial liabilities, the change in fair value is to be
accounted for as follows:

- The change attributable to changes in credit risk are presented in other comprehensive income (OCI)

- The remaining change is presented in profit or loss

AASB 9 also removes the volatility in profit or loss that was caused by changes in the credit risk of
liabilities elected to be measured at fair value. This change in accounting means that gains or losses
attributable to changes in the entity’s own credit risk would be recognised in OCI. These amounts
recognised in OCI are not recycled to profit or loss if the liability is ever repurchased at a discount.

Impairment

The final version of AASB 9 introduces a new expected-loss impairment model that will require
more timely recognition of expected credit losses. Specifically, the new Standard requires entities
to account for expected credit losses from when financial instruments are first recognised and to
recognise full lifetime expected losses on a more timely basis.

Notes to the Financial StatementFor the year ended 30 June 20162. Summary of significant accounting policies continued

b) Statement of compliance continued

Hedge accounting

Amendments to AASB 9 (December 2009 & 2010 editions and AASB 2013-9) issued in December
2013 included the new hedge accounting requirements, including changes to hedge effectiveness
testing, treatment of hedging costs, risk components that can be hedged and disclosures.

Consequential amendments were also made to other standards as a result of AASB 9, introduced
by AASB 2009-11 and superseded by AASB 2010-7, AASB 2010-10 and AASB 2014-1 – Part E.

AASB 2014-7 incorporates the consequential amendments arising from the issuance of AASB 9 in
Dec 2014.

AASB 2014-8 limits the application of the existing versions of AASB 9 (AASB 9 (December 2009)
and AASB 9 (December 2010)) from 1 February 2015 and applies to annual reporting periods
beginning on after 1 January 2015.

Application Date of the Standard

1 January 2018

Application date for Group

1 July 2015

Impact on Group financial report

The impact of early adopting AASB 9 is discussed at Note 23.

(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 2016,
are outlined below:

AASB 2014-3

Summary

Amendments to Australian Accounting Standards – Accounting for Acquisitions of Interests
in Joint Operations
[AASB 1 & AASB 11]

AASB 2014-3 amends AASB 11 to provide guidance on the accounting for acquisitions of interests
in joint operations in which the activity constitutes a business. The amendments require:-

(a) the acquirer of an interest in a joint operation in which the activity constitutes a business, as

defined in AASB 3 Business Combinations, to apply all of the principles on business
combinations accounting in AASB 3 and other Australian Accounting Standards except for
those principles that conflict with the guidance in AASB 11; and

(b) the acquirer to disclose the information required by AASB 3 and other Australian Accounting

Standards for business combinations.

This Standard also makes an editorial correction to AASB 11.

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 format is not expected to have a material impact on

the Group.

AASB 2014-4

Summary

Clarification of Acceptable Methods of Depreciation and Amortisation (Amendments to IAS 16
and IAS 38)

AASB 116 and AASB 138 both establish the principle for the basis of depreciation and amortisation
as being the expected pattern of consumption of the future economic benefits of an asset.

The IASB has clarified that the use of revenue-based methods to calculate the depreciation of an
asset is not appropriate because revenue generated by an activity that includes the use of an asset
generally reflects factors other than the consumption of the economic benefits embodied in the asset.

The amendment also clarified that revenue is generally presumed to be an inappropriate basis
for measuring the consumption of the economic benefits embodied in an intangible asset.
This presumption, however, can be rebutted in certain limited circumstances.

Application Date of the Standard

1 January 2016

Application Date for Group

1 July 2016

Impact on Group Financial report The Group currently uses diminishing value and units of production bases for the calculation of

depreciation and amortisation. This standard will have no impact upon the Group’s current
methodologies.

Notes to the Financial StatementFor the year ended 30 June 2016
2. Summary of significant accounting policies continued

b) Statement of compliance continued

AASB 15

Summary

Revenue from Contracts with Customers

In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers, which replaces IAS
11 Construction Contracts, IAS 18 Revenue and related Interpretations (IFRIC 13 Customer Loyalty
Programmes, IFRIC 15 Agreements for the Construction of Real Estate, IFRIC 18 Transfers of Assets
from Customers and SIC-31 Revenue—Barter Transactions Involving Advertising Services).

The core principle of IFRS 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 January 2018

Impact on Group Financial report The group is currently assessing the impact of this standard.

AASB 1057

Summary

Application of Australian Accounting Standards

This Standard lists the application paragraphs for each other Standard (and Interpretation),
grouped where they are the same. Accordingly, paragraphs 5 and 22 respectively specify the
application paragraphs for Standards and Interpretations in general. Differing application
paragraphs are set out for individual Standards and Interpretations or grouped where possible.

The application paragraphs do not affect requirements in other Standards that specify that certain
paragraphs apply only to certain types of entities.

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 format is not expected to have a material impact on

the Group.

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 2016

Application Date for Group

1 July 2016

Impact on Group Financial report The adoption of this standard in the current format is not expected to have a material impact on

the Group.

Notes to the Financial StatementFor the year ended 30 June 20162. 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 subjects of the principal amendments to the Standards are set out below:

AASB 5 Non-current Assets Held for Sale and Discontinued Operations:-

• Changes in methods of disposal – where an entity reclassifies an asset (or disposal group) directly
from being held for distribution to being held for sale (or vice versa), an entity shall not follow the
guidance in paragraphs 27–29 to account for this change.

AASB 7 Financial Instruments: Disclosures:-

• Servicing contracts - clarifies how an entity should apply the guidance in paragraph 42C of AASB
7 to a servicing contract to decide whether a servicing contract is ‘continuing involvement’ for the
purposes of applying the disclosure requirements in paragraphs 42E–42H of AASB 7.

• Applicability of the amendments to AASB 7 to condensed interim financial statements - clarify that
the additional disclosure required by the amendments to AASB 7 Disclosure–Offsetting Financial
Assets and Financial Liabilities is not specifically required for all interim periods. However, the
additional disclosure is required to be given in condensed interim financial statements that are
prepared in accordance with AASB 134 Interim Financial Reporting when its inclusion would be
required by the requirements of AASB 134.

AASB 119 Employee Benefits:

• Discount rate: regional market issue - clarifies that the high quality corporate bonds used to

estimate the discount rate for post-employment benefit obligations should be denominated in
the same currency as the liability. Further it clarifies that the depth of the market for high quality
corporate bonds should be assessed at the currency level.

AASB 134 Interim Financial Reporting:-

• Disclosure of information ‘elsewhere in the interim financial report’ – amends AASB 134 to

clarify the meaning of disclosure of information ‘elsewhere in the interim financial report’ and to
require the inclusion of a cross-reference from the interim financial statements to the location of
this information.

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 is not expected to have a material impact on the Group.

AASB 2015-2

Summary

Amendments to Australian Accounting Standards – Disclosure Initiative: Amendments to
AASB 101

The Standard makes amendments to AASB 101 Presentation of Financial Statements arising from
the IASB’s Disclosure Initiative project. The amendments are designed to further encourage
companies to apply professional judgment in determining what information to disclose in the
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. The amendments also clarify that companies should use
professional judgment in determining where and in what order information is presented in the
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 is not expected to have a material impact on the Group.

Notes to the Financial StatementFor the year ended 30 June 20162. Summary of significant accounting policies continued

b) Statement of compliance continued

AASB 2015-9

Summary

Amendments to Australian Accounting Standards – Scope and Application Paragraphs
[AASB 8, AASB 133 & AASB 1057]

This Standard inserts scope paragraphs into AASB 8 and AASB 133 in place of application paragraph
text in AASB 1057. This is to correct inadvertent removal of these paragraphs during editorial changes
made in August 2015. There is no change to the requirements or the applicability of AASB 8 and
AASB 133.

Application Date of the Standard

1 July 2016

Application Date for Group

1 July 2016

Impact on Group Financial report The adoption of this standard is not expected to have a material impact on the Group.

AASB 16

Summary

Leases

The key features of AASB 16 are as follows:

Lessee accounting

• Lessees are required to recognise assets and liabilities for all leases with a term of more than 12

months, unless the underlying asset is of low value.

• A lessee measures right-of-use assets similarly to other non-financial assets and lease liabilities

similarly to other financial liabilities.

• Assets and liabilities arising from a lease are initially measured on a present value basis. The

measurement includes non-cancellable lease payments (including inflation-linked payments), and
also includes payments to be made in optional periods if the lessee is reasonably certain to exercise
an option to extend the lease, or not to exercise an option to terminate the lease.

• AASB 16 contains disclosure requirements for lessees.

Lessor accounting

• AASB 16 substantially carries forward the lessor accounting requirements in AASB 117.

Accordingly, a lessor continues to classify its leases as operating leases or finance leases, and to
account for those two types of leases differently.

• AASB 16 also requires enhanced disclosures to be provided by lessors that will improve information

disclosed about a lessor’s risk exposure, particularly to residual value risk.

AASB 16 supersedes:

(a) AASB 117 Leases

(b) Interpretation 4 Determining whether an Arrangement contains a Lease

(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 July 2019

Application Date for Group

1 July 2019

Impact on Group Financial report The group is currently assessing the impact of this standard.

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 July 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.

Notes to the Financial StatementFor the year ended 30 June 20162. Summary of significant accounting policies continued

b) Statement of compliance continued

AASB 2016-5

Summary

Classification and Measurement of Share-based Payment Transactions

This standard amends to AASB 2 Share-based Payment, clarifying how to account for certain types of
share-based payment transactions. The amendments provide requirements on the accounting for:

• The effects of vesting and non-vesting conditions on the measurement of cash-settled share-

based payments.

• Share-based payment transactions with a net settlement feature for withholding tax obligations.

• A modification to the terms and conditions of a share-based payment that changes the classification

of the transaction from cash-settled to equity-settled.

Application Date of the Standard

1 July 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.

The Group has not early adopted any other standard, interpretation or amendment that has been issued but is not yet effective.

c) Basis of consolidation

The consolidated financial statements are those of the consolidated entity, comprising Cooper Energy Limited (“the parent entity”) and its
subsidiaries (“the Group”).

The financial statements of subsidiaries are prepared for the same reporting period as the parent entity, using consistent accounting policies.
Adjustments are made to bring into line any dissimilar accounting policies that may exist. All inter-company balances and transactions, income
and expenses and profit and losses arising from intra-group transactions, have been eliminated in full.

Subsidiaries are consolidated from the date on which control is transferred to the Group and cease to be consolidated from the date on which
control is transferred out of the Group.

d) Business combinations

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.

Notes to the Financial StatementFor the year ended 30 June 20162. Summary of significant accounting policies continued

e) Joint arrangements

The Group has an interest 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 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 (classified as discontinued operations), which has a US dollar functional currency, all other foreign operations of
the group have an Australian dollar functional currency.

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.

Available-for-sale Investments (applicable to the 2015 financial year only)

Investments are classified as available-for-sale 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. Designation will be re-evaluated at each financial year-end.

After initial recognition, investments are remeasured to fair value. Changes in the fair value of available-for-sale investments are recognised
as a separate component of equity until the investment is sold, collected or otherwise disposed of, or until the investment is determined to
be impaired when there is a significant or prolonged decline in the fair value, at which time the cumulative change in fair value previously
reported in equity is included in earnings.

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.

Notes to the Financial StatementFor the year ended 30 June 20162. Summary of significant accounting policies continued

h) Revenue and cost recognition continued

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 properties are amortised on the Units of Production basis using the latest approved estimate of proved and probable (2P) reserves.
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 on national government 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 in section 4 of the Directors’ Report.

k) Share based payments

The Group provides benefits to employees (including Executive Directors) of the Group in the form of share-based payment transactions,
whereby employees render services in exchange for rights over shares (“equity-settled transactions”).

The cost of these equity-settled transactions with employees is measured by reference to the fair value at the date at which they are
granted and are recorded as an expense, with a corresponding increase in reserves, on a straight-line basis over the vesting period of the
related instrument.

The fair value is determined using the Black-Scholes methodology to produce a Monte-Carlo simulation model that takes into account the
exercise price, the vesting period, the vesting and performance criteria, the impact of dilution, the non-tradable nature of the performance
right or share appreciation right, the share price at grant date, the expected price volatility of the underlying share, the expected dividend
yield and the risk-free interest rate for the term of the vesting period. The fair value of the performance rights and share appreciation rights
granted excludes the impact of any non-market vesting conditions (for example, profitability and sales growth targets).

The volatility assumption is based on the actual volatility of Cooper Energy’s daily closing share price over the three year period to the
valuation date.

The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the
performance and/or service conditions are fulfilled, ending on the date on which the relevant employees become fully entitled to the award
(the vesting period).

The cumulative expense recognised for equity-settled transactions at each reporting date until vesting date reflects:

1. the extent to which the vesting period has expired; and

2. the Group’s best estimate of the number of equity instruments that will ultimately vest.

No adjustment is made for the likelihood of market performance conditions being met as the effect of these conditions is included in the
determination of fair value at grant date. The Consolidated Statement of Comprehensive Income charge or credit for a period represents
the movement in cumulative expense recognised as at the beginning and end of that period.

No expense is recognised for awards that do not ultimately vest, except for awards where vesting is only conditional upon a
market condition.

If the terms of an equity-settled award are modified, as a minimum an expense is recognised as if the terms had not been modified.
In addition, an expense is recognised for any modification that increases the total fair value of the share-based payment arrangement,
or is otherwise beneficial to the employees as measured at the date of modification.

Notes to the Financial StatementFor the year ended 30 June 20162. Summary of significant accounting policies continued

k) Share based payments continued

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.

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 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.

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.

Notes to the Financial StatementFor the year ended 30 June 20162. Summary of significant accounting policies continued

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.

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 properties.

p) Oil properties

Oil properties 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.

Notes to the Financial StatementFor the year ended 30 June 20162. Summary of significant accounting policies continued

q) Provision for restoration continued

A restoration provision is recognised after the construction of the facility and then reviewed on an annual basis.

When the liability is recorded the carrying amount of the production assets is increased by the asset retirement costs and 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.

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.

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.

Notes to the Financial StatementFor the year ended 30 June 20162. Summary of significant accounting policies continued

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.

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. 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.

Notes to the Financial StatementFor the year ended 30 June 20162. Summary of significant accounting policies continued

bb) Significant accounting judgements, estimates and assumptions continued

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 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.

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 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 properties and property, plant & equipment

The Group reviews the carrying amount of oil properties 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.

Notes to the Financial StatementFor the year ended 30 June 20162. Summary of significant accounting policies continued

bb) Significant accounting judgements, estimates and assumptions continued

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 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

The Group operates in various geographical locations and prepares reports internally and externally by continental geographical segments.
Within each segment, the costs of operations and income are prepared firstly by legal entity and then by joint venture. Revenue and
outgoings are allocated by way of their natural expense and income category. These reports are drawn up on a monthly basis. Resources
are allocated between each segment on an as needs basis. Selective reporting is provided to each Board meeting while the annual and
bi-annual results are reported to the Board. The Managing Director is the chief operating decision maker.

Other prospective opportunities outside of these geographical segments are also considered from time to time and, if they are secured,
will then be attributed to the continental geographical segment where they are located.

The current external customers by geographical location of production are the Australian Business Unit with two customers and the Asian
Business Unit with one customer.

The following are the current geographical segments:

Australian Business Unit

Exploration and evaluation for oil and gas, development, production and sale of crude oil in a number of areas in the Cooper Basin,
Gippsland Basin and Otway 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. Interest income is earned from
the placement of funds with various Australian Banks for periods of up to 12 months.

Asian Business Unit

The Asian business unit involves the production and sale of crude oil from the Tangai-Sukananti KSO. It is located on the island of
Sumatra, Indonesia. Revenue is derived from the sale of crude oil to PT Pertamina EP. The Group is also involved in exploration and
evaluation for oil and gas in the Sumbagsel and Merangin III Permit areas on the island of Sumatra, Indonesia. During the first half
of 2016 the Company commenced the sale process for the Indonesian operations and received expressions of interest for the sale of
the Group’s Indonesian assets. During the financial year, the sale of the exploration assets completed and an agreement was signed in
respect of the sale of the producing asset estimated to be completed in early FY17.

The Indonesian operations have been classified as assets held for sale and discontinued operations at June 2016.

African Business Unit

Exploration and evaluation for oil and gas in the Bargou, Nabeul and Hammamet permit areas off the coast of Tunisia. No income is
derived from these units. The Company has announced its intention to dispose of the equity interests in the Tunisian assets. During the
period the Company has withdrawn from the Hammamet joint venture and has exited the Nabeul joint venture. In the remaining Tunisian
tenement, the Bargou permit, the joint venture agreed and is in the process of completing a reduced work program consisting of seismic
acquisitions and well abandonment to fulfil its commitments. The Company is planning on selling its interest in the joint venture and has
therefore classified Bargou as held for sale at 30 June 2016. The African operations have been classified as discontinued operations.

European Business Unit

The Company has disposed of all exploration interests in Poland and has liquidated the Polish and Dutch entities during the first half of
the 2016 financial year. The European business unit is classified as discontinued operations.

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.

Notes to the Financial StatementFor the year ended 30 June 20163. Segment reporting continued

The following table presents revenue and segment results for reportable segments.

Geographical Segments

Elimination

Australian
Business
Unit

Continuing
Operations
Total

Asian
Business
Unit (disc.
operation)

European
Business
Unit (disc.
operation)

African
Business
Unit (disc.
Operation)

Discontinued
Operations
Total

Consolidated

$’000

Year ended 30 June 2016

Revenue

20,257

Other income and revenue

800

Total consolidated revenue

21,057

Depreciation of property

(284)

Amortisation of
development costs

Amortisation of
exploration costs

Impairment

(2,461)

(405)

(21,865)

Share of loss in associate

(87)

Finance costs

Share based payments

Exit provision

Exploration costs
written off

(1,392)

(1,884)

292

20,257

7,169

850

21,107

7,169

(284)

(178)

(2,461)

(1,251)

(405)

(21,865)

(11,446)

(87)

(1,392)

(1,884)

292

7,169

27,426

850

7,169

28,276

(178)

(462)

(1,251)

(3,712)

(405)

(374)

(11,820)

(33,685)

(87)

(1,392)

(1,884)

(3,663)

(180)

112

Segment result

(26,045)

(25,995)

(12,038)

(14)

(4,486)

(16,524)

(42,519)

Income tax

Net Profit

Segment liabilities

Segment assets

Non-Current Assets

Cash flow from:

80,473

170,690

118,048

- Operating activities

6,771

- Investing activities

(11,970)

- Financing

21,171

Capital Expenditure

(24,409)

7,680

(34,839)

80,473

378

170,690

5,231

118,048

3,930

4,308

84,781

410

5,641

176,331

118,123

6,771

1,392

(11)

(217)

1,164

7,935

(11,970)

(6,254)

21,171

(24,409)

(6,223)

(1,764)

(8,018)

(19,988)

21,171

(1,764)

(7,987)

(32,396)

Notes to the Financial StatementFor the year ended 30 June 2016

3. Segment reporting continued

Geographical Segments

Elimination

Australian
Business
Unit

Continuing
Operations
Total

Asian
Business
Unit (disc.
operation)

European
Business
Unit (disc.
operation)

African
Business
Unit (disc.
Operation)

Discontinued
Operations
Total

Consolidated

$’000

Year ended 30 June 2015

Revenue

33,510

5,574

Other income and revenue

2,423

(556)

1,867

Total consolidated revenue

35,933

(556)

35,377

5,574

Depreciation of property

(397)

Amortisation of
development costs

Amortisation of
exploration costs

Impairment

Share of loss in associate

Finance costs

(5,255)

(771)

(22,642)

(166)

(495)

Share based payments

(1,629)

Exploration costs
written off

(2,342)

(397)

(72)

(5,255)

(2,249)

(771)

(22,642)

(166)

(495)

(1,629)

(2,342)

5,574

39,084

1,867

5,574

40,951

(72)

(469)

(2,249)

(7,504)

(771)

(141)

(47,485)

(47,626)

(7 0,268)

(166)

(495)

(1,629)

(2,342)

Segment result

(17,669)

(556)

(18,225)

(562)

(47,792)

(48,332)

(66,423)

Income tax

Net Profit

Segment liabilities

67,168

(235)

66,933

1,675

Segment assets

148,001

(235)

147,766

25,902

101,972

18,215

2,955

(63,468)

1,521

3,196

70,129

318

26,234

174,000

18,215

120,187

Non-Current Assets

101,972

Cash flow from:

- Operating activities

5,802

- Investing activities

(12,862)

- Financing

Capital Expenditure

(18,966)

5,802

(2,132)

(132)

(1,503)

(3,767)

2,035

(12,862)

2,219

141

(18,966)

(8,064)

325

2,685

(10,175)

(392)

(8,456)

(27,422)

Revenue from external customers by geographical location of production

Australia

Indonesia

Total revenue

Revenue from one customer amounted to $19,304,000 (2015: $32,220,000) arising from oil sales.

2016
$’000

2015
$’000

20,257

33,510

7,169

5,574

27,426

39,084

Notes to the Financial StatementFor the year ended 30 June 2016

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 oil operations

Oil sales

Total revenue from oil sales

Other revenue

Interest revenue

Gain on acquisition of associate

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

Fair value adjustment of success fee liability

Total finance costs

Other expenses

Depreciation of property, plant and equipment

General administration (includes employee benefits and lease payments)

Plant care and maintenance

Loss on fair value of oil price derivative

Consolidated

2016
$’000

2015
$’000

20,257

33,510

777

850

1,225

281

361

1,867

(8,181)

(11,106)

(1,133)

(2,457)

(405)

(771)

(2,461)

(5,255)

(12,180)

(19,589)

(1,399)

(1,433)

(12)

(1,392)

(310)

1,248

(495)

(284)

(397)

(10,781)

(12,135)

(634)

(275)

Losses from change in fair value of derivative financial asset designated as fair value through profit and loss

(206)

Loss on deemed disposal of associate

Realised and unrealised foreign currency translation gain

Total other expenses

Employee benefits expense

Director and employee benefits

Share based payments

Superannuation expense

Lease payments

Minimum lease payment – operating lease

(105)

209

736

(11,870)

(12,002)

(3,842)

(5,067)

(1,884)

(1,629)

(380)

(364)

(6,106)

(7,060)

(328)

(326)

Notes to the Financial StatementFor the year ended 30 June 20165. 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 expense

Petroleum Resource Rent Tax - deferred tax

Total tax benefit

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% (2015: 30%)

Increase/(decrease) in income tax expense due to:

Non-assessable income

Non-deductible expenditure

(Derecognition) / Recognition of capital losses

Adjustments in respect to current income tax of previous years

Non Australian taxation jurisdictional subsidiaries

Total

Income tax benefit

Income tax recognised in other comprehensive income

Fair value movement on derivative financial instruments

Revaluation of available for sale financial assets

Income tax using the domestic corporation tax rate of 30% (2015: 30%)

Consolidated

2016
$’000

2015
$’000

205

7,543

159

7,702

7,907

847

2,242

3,089

7,907

3,089

(25,995)

(18,225)

7,799

5,468

1,055

(232)

364

(24)

108

7,907

300

(2,914)

(1,346)

826

(2,379)

3,089

1,346

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 intercompany 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.

Notes to the Financial StatementFor the year ended 30 June 2016
5. Income tax continued

Unrecognised temporary differences

At 30 June 2016, 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 (2015 $nil).

Franking Tax Credits

At 30 June 2016 the parent entity had franking tax credits of $42,856,152 (2015: $43,715,169). The fully franked dividend equivalent is
$99,997,690 (2015 $102,002,060).

PRRT

Cooper Energy Limited has not recognised a Deferred Tax Asset for the Petroleum Rent Resource Tax of $26,623,000 (2015:
$22,341,000) 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 2016 of $7,661,000 (2015: $676,797).

(b) Capital Losses

Cooper Energy has not recognised a Deferred Tax Asset for Australian income tax capital losses of $60,108,000 (2015: $22,207,705) on
the basis that it is not probable that the carried forward capital losses will be utilised against future assessable capital profits.

Deferred income tax from corporate tax

Deferred income tax at 30 June relates to the following:-

Deferred tax liabilities

Trade and other receivables

Oil properties

Exploration and evaluation

Provisions

Unrealised currency translation gain

Deferred tax assets

Property, plant & equipment

Oil properties

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

2016
$’000

2015
$’000

2016
$’000

2015
$’000

933

1,574

641

17,588

11,706

(5,882)

416

144

(158)

144

18,521

13,840

1,762

1,296

575

5,640

496

199

7,661

681

125

677

16,345

2,820

(2)

466

(29)

(106)

5,640

320

6,984

216

1,624

931

(416)

(22)

(3)

1,296

(13)

169

168

677

Deferred tax income (expense)

8,207

3,454

Deferred tax liability from corporate tax

2,176

11,020

Notes to the Financial StatementFor the year ended 30 June 20165. Income tax continued

Deferred income tax from petroleum resource rent tax

Deferred income tax at 30 June relates to the following:-

Deferred tax liabilities

Exploration and evaluation

Deferred tax assets

Oil properties

As represented on the Consolidated Statement of Financial Position,
deferred tax asset

Consolidated
Statement of
Financial Position

Consolidated Statement
of Comprehensive
Income

2016
$’000

2015
$’000

2016
$’000

2015
$’000

As represented on the Consolidated Statement of Financial Position,
net deferred tax liability

2,176

11,020

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 2016 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

(18,088)

(15,136)

Consolidated

2016
$’000

2015
$’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)

2016
Thousands

2015
Thousands

343,602

330,905

343,602

330,905

(5.3)

(4.6)

Notes to the Financial StatementFor the year ended 30 June 20166. Earnings per share continued

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)

Consolidated

2016
$’000

2015
$’000

(34,839)

(63,468)

2016
Thousands

2015
Thousands

343,602

330,905

343,602

330,905

(10.1)

(19.2)

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.

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

2016
$’000

16,815

32,902

49,717

2015
$’000

7,380

31,993

39,373

(i) Short-term deposits at bank are in Australian dollars and are generally for periods of three months or less and earn interest at

money market interest rates. This amount also includes term deposits of $10 million which have a maturity greater than 3 months,
but which are not subject to significant break costs should the Group wish to withdraw these funds before maturity.

(ii) The carrying value of the term deposit approximates its fair value.

In the September quarter 2015, the Group completed the restructuring of its bank facilities with Westpac Banking Corporation (Westpac)
from corporate to reserve based lending. The facilities are secured, committed to 30 June 2018 and comprise up to $35 million for
general corporate purposes (debt funding) and $5 million for bank guarantees.

Based on reserves and forward prices as at 30 June 2015 the facilities provided $21 million of available debt funding at that time.
The available debt funding is subject to bi-annual recalculation based on reserves, forward prices and the Company’s latest forecasts.
The 31 December 2015 recalculation provided approximately $15 million in available debt funding which remain undrawn. Based on
existing reserves and forecasts (excluding the Indonesian production assets) it is estimated that the facilities will provide approximately
$10 million in available debt funding when the 30 June 2016 recalculation is finalised with Westpac by 30 September 2016.

Notes to the Financial StatementFor the year ended 30 June 20167. 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:

Amortisation of development costs in areas of production

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

Loss on sale of assets held for sale

Share of loss in associate

Reclassification of fair value movement on sale of available for sale investments

Share based payments

Finance cost

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 tax liabilities

(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

Trade receivables (i)

Related party receivables (ii)

Related party receivables – joint ventures (iii)

Hedge settlement receivable

Interest receivable

Total (iv)

Consolidated

2016
$’000

2015
$’000

(34,839)

(63,468)

3,712

7,504

405

462

771

469

(112)

2,342

3,663

33,685

70,127

904

1,884

1,392

138

275

3,513

940

337

166

(3,634)

1,629

496

(444)

(856)

(651)

(8,844)

(3,411)

(922)

859

4,539

(4,143)

(3,407)

(5,899)

(140)

349

7,935

2,035

Consolidated

2016
$’000

2,956

170

125

2015
$’000

11,406

238

201

156

3,400

12,001

Notes to the Financial StatementFor the year ended 30 June 2016Consolidated

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.

(iv) Due to the short-term nature of the trade and other receivables, the carrying value approximates fair value.

9. Prepayments

Bank facility fee

Insurance

Other

10. Available for sale investments

Shares at fair value

A reconciliation of the movement during the year is as follows:-

Opening balance

Purchases

Reclassification as investment in associate

Reclassification as equity instrument at fair value through other comprehensive income

Fair value movement

Sale of investment

Closing balance

11. 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 on adoption of AASB 9

Fair value movement

Closing balance

2016
$’000

154

142

303

2016
$’000

790

1,343

(553)

790

The equity investments consist of one investment and the Group has received no dividends throughout the financial year.

On adoption of AASB 9 the Group’s available for sale investments were reclassified as equity instruments. Refer to Note 23 for further
information on the early adoption of AASB 9.

2015
$’000

316

324

640

2015
$’000

1,343

26,040

(712)

(8,325)

(15,660)

1,343

2015
$’000

Notes to the Financial StatementFor the year ended 30 June 2016
12. Assets held for sale and discontinued operations

Indonesia

During the first half of 2016 the Company received expressions of interest for the sale of the Group’s Indonesian assets. On 1 June
2016, the Company completed the sale of the Indonesian exploration assets for consideration of US$8.25 million. On 7 June 2016
the Company signed a Share Sale Agreement for the sale of the Cooper Energy subsidiary holding the Indonesian production asset to
Bow Energy International Holdings Inc (a subsidiary of ACL International Ltd) and Lamara Energy Pte for consideration of US$4.3 million.
The Indonesian production asset has been classified as assets held for sale and the Indonesian operations have been classified as
discontinued operations at 30 June 2016. The Indonesian production assets have been impaired to the fair value less cost to sell.

Tunisia

The Group has exited the Hammamet and Nabeul joint ventures during the year. Following the positive results of the 3D seismic
acquisition, the Group has recommenced a process to sell its interest in the Bargou joint venture. The Group’s Tunisian assets are also
classified as discontinued operations at 30 June 2016 with the Group’s interest in Bargou classified as held for sale.

The losses from discontinued operations are presented on a separate line in the Consolidated Statement of Comprehensive Income.

2016
$’000

3,861

819

108

4,788

(282)

(221)

(142)

(645)

4,143

2015
$’000

7,169

5,574

(11,873)

(6,146)

(11,820)

(47,626)

(16,524)

(48,198)

(227)

(134)

(16,751)

(48,332)

1,164

(3,055)

(1,891)

(4.9)

(14.6)

Trade and other receivables

Oil properties

Other assets

Total assets held for sale

Trade and other payables

Provisions

Other liabilities

Liabilities and provisions associated with assets held for sale

Net assets directly associated with disposal group

Revenue for the year from discontinued operations

Expenses for the year from discontinued operations

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)

Notes to the Financial StatementFor the year ended 30 June 201613. Investments in associate

The group has a 13.94% (2015: 21.55%) interest in Bass Strait Oil Company Limited (ASX: BAS), which is involved in oil and gas
exploration in the Gippsland basin, offshore Victoria, Australia. The Group’s interest in Bass Strait Oil Company 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 Strait Oil Company Limited, and
therefore commenced accounting for the investment as an investment in associate. Notwithstanding the Company’s reduced voting power,
significant influence still exists due to the Company’s presence on the Board of Bass Strait Oil Company Limited.

The following table illustrates the summarised preliminary and unaudited financial information of the Group’s investment in Bass Strait Oil
Company Limited. This information is based on the latest management accounts and is subject to change on finalisation:

Current assets

Non-current assets

Current liabilities

Non-current liabilities

Equity

Group’s share of net assets

Reconciliation to Group’s carrying amount of investment

Dilution through rights issue and capital injection

Impairment

Prior year impairment 1

Group’s carrying amount of the investment

Loss before tax

Income tax expense

Loss for the year

Total comprehensive expenditure for the year

Group’s share of loss for the year (continuing operations)

2016
$’000

492

4,444

2015
$’000

841

4,279

(131)

(163)

4,805

670

(154)

(343)

173

(587)

(37)

(624)

(87)

4,957

1,068

(18)

(530)

520

(802)

(35)

(837)

(166)

1. The prior year impairment is impacted by the movement in the Group’s interest in its associate during the 2016 financial year and

represents the historical impairment charges at its current 13.94% interest.

The associate had no contingent liabilities at 30 June 2016.

The investment in associate has been impaired and is carried at fair value. The Group has used the associate’s quoted share price at
30 June 2016 as an approximation of its fair value.

Notes to the Financial StatementFor the year ended 30 June 20162016
$’000

5,385

2015
$’000

7,624

4,297

5,385

11,921

Transferred Exploration
and Evaluation

Development

Total

$’000

1,778

10,143

11,921

(4,297)

627

(405)

(2,461)

(2,866)

1,373

4,012

5,385

5,174

27,134

32,308

(3,801)

(23,122)

(26,923)

1,373

4,012

5,385

2,348

15,855

18,293

111

9,244

9,355

(771)

(7,504)

(8,275)

(7,484)

1,778

10,143

11,921

5,174

35,356

40,530

(3,396)

(25,213)

(28,609)

1,788

10,143

11,921

14. Oil properties

Regions of focus

Australia

Asia

Total oil properties

Consolidated

Year end 30 June 2016

Carrying amount at 1 July 2015

Classified as held for sale

Additions

Depreciation

Carrying amount at 30 June 2016

As at 30 June 2016

Cost

Accumulated depreciation & impairment

Year end 30 June 2015

Carrying amount at 1 July 2014

Additions

Foreign currency adjustment

Depreciation

Impairment

Carrying amount at 30 June 2015

As at 30 June 2015

Cost

Accumulated depreciation

Notes to the Financial StatementFor the year ended 30 June 201615. Impairment

The following impairment losses were recognised during the financial year:-

Impairment

Available for sale financial assets

Investments in associates

Exploration & Evaluation

Oil Properties – PEL 93

Total

Consolidated

2016
$’000

2015
$’000

(7,471)

(154)

(21,711)

(530)

(7,157)

(7,484)

(21,865)

(22,642)

In accordance with the Group’s accounting policies and procedures, the Group performs its impairment testing bi-annually.

Exploration and Evaluation Impairment

As outlined in Note 2 (bb) (ii), exploration and evaluation costs are accumulated separately for each Area Of Interest (AOI) and carried
forward provided that one of the following conditions is met:

• Such costs are expected to be recouped through success development or sale; or

• Exploration activities have not yet reached a stage which permits a reasonable assessment of the existence or otherwise of economically

recoverable reserves, and active and significant operations in relation to the area are continuing.

Significant judgement is required in determining whether it is likely that future economic benefits will be derived from capitalised
exploration and evaluation expenditure. In the judgement of the Group, at 30 June 2016 exploration activities in each AOI, where costs
are carried forward, have not reached a stage which permits a reasonable assessment of the existence or otherwise of economically
recoverable reserves. Activities in relation to each AOI with expenditure carried forward at 30 June 2016 are continuing. Nothing has
come to the attention of the Group to indicate future economic benefits will not be achieved. The Directors are continually monitoring the
AOIs and are exploring alternatives for funding the development of AOIs when economic recoverable reserves are confirmed.

During the financial year the Group’s exploration assets in the Otway basin were reviewed for impairment. Following this assessment,
due to market conditions and no further clarity on the Victorian permits, for which there is a moratorium until the Victorian government
completes its assessment of the impact of hydraulic fracturing, the decision was made to impair PEP 168 and impair the Otway onshore
deep troughs AOI by the amount of the fair value premium paid on the acquisition of Somerton Energy.

Additionally, the Cooper Basin Northern licenses, PEL 90, PEL 100 and PEL 110 were tested for impairment due to impairment indicators
being present. To date, no commercially viable prospects have been discovered in these permits. These assets were impaired to nil during
the first-half of the financial year – no further impairment losses were recognised in the second half.

Further impairment losses were also recognised on the Group’s Tunisian assets during the first-half of the financial year relating to further
capitalised exploration expenditure. Exploration and evaluation costs incurred during the second half in the Nabeul and Hammamet
permits have been recognised directly in the income statement as exploration and evaluation expenditure written off.

The total impairment recognised in respect of exploration and evaluation assets was $21.7 million and is summarised in the table below
with the relevant asset’s remaining recoverable amount.

Exploration Asset

PEL 90

PEL 100

PEL 110

Otway Onshore Deep Troughs

PEP 168

Total

Oil Properties Impairment

Impairment Recognised
$’000

Recoverable Amount
$’000

933

1,592

1,540

11,694

5,952

21,711

100

12,430

12,632

A number of factors represented indicators of impairment at 30 June 2016, including the continued low oil price throughout the period.
As a result, the Group assessed the recoverable amounts of its Cash Generating Units (CGUs).

Notes to the Financial StatementFor the year ended 30 June 201615. Impairment continued

Impairment Testing

i) Methodology

Impairment is recognised when the carrying amount exceeds the recoverable amount of a CGU. The recoverable amount of each CGU
has been estimated using its value in use (VIU).

Value in use is estimated based on discounted cash flows using market based commodity price exchange rate assumptions, estimated
production forecasts based on 2P reserves, operating costs and capital expenditure based on current development plans.

Estimates of production, operating costs and capital expenditure are sourced from our planning process including specific development
plans of each CGU.

ii) Key Assumptions

The table below summarises the key assumptions used:-

Real oil price (US$ per bbl)

AUD:USD exchange rate

CPI (%)

Pre-tax real discount rate (%)

30 June 2016

30 June 2015

2017-2018

Long-term
(2019 +)

2016-2018

Long-term
(2019 +)

$45 increasing
to $60

$65 $65 increasing
to $75

$0.74

1.5%

$0.72

1.5%

$0.80

2.5%

$80

$0.80

2.5%

AUD assets 11.5%
USD assets 16.3%

AUD assets 11.2%
USD assets 15.0%

Commodity prices and exchange rates

Oil price and exchange rates are estimated with reference to external data and are reviewed quarterly. The rates applied have been
obtained from spot and forward values and market analysis including equity analyst estimates.

Discount rate

In determining the VIU, the future cash flows were discounted using rates based on the Group’s real pre-tax weighted average cost
of capital, in line with the Capital Asset Pricing Model, for each functional currency with additional premiums being applied based on
geographical location and current economic conditions.

Production, operating and capital costs

Production forecasts have been based on 2P developed and undeveloped reserves. The forecasts include all capital required to produce
the reserves and, where applicable, develop the undeveloped reserves.

iii) Impacts

As a result of impairment testing, the recoverable amount of PEL 93 continues to be nil and no further impairment losses were recognised.

Sensitivity Analysis

Any change to the assumptions used to determine the VIU could result in a change to the recoverable amount. Given the degree of
change required to each individual input before an impairment reversal on PEL 93 would be indicated, impairment reversal is not likely.

In addition to the impairment testing performed over PEL 93, testing was performed over PEL 92. The results of this testing indicated that
the CGU’s recoverable amount was higher than its carrying amount. No impairment was recognised in respect of PEL 92. Any reasonable
change in assumptions would not result in an impairment of PEL 92.

Notes to the Financial StatementFor the year ended 30 June 201616. Property, plant & equipment

Consolidated

Year end 30 June

Carrying amount at 1 July

Additions

Disposals/written off

Depreciation

Carrying amount at 30 June

As at 30 June

Cost

Accumulated depreciation

17. Exploration and evaluation

Regions of focus

Australia

Asia

Total 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

Transferred to oil properties

Unsuccessful exploration wells written back/(off) (i)

Impairment

Carrying amount at 30 June (ii)

Consolidated

2016
$’000

2015
$’000

981

(34)

(284)

708

1,141

237

(397)

981

2,101

2,142

(1,393)

(1,161)

708

981

Consolidated

2016
$’000

2015
$’000

110,976

91,489

13,874

110,976

105,363

94,621

(15,270)

22,878

7,750

19,424

12,602

292

(111)

(2,342)

(21,711)

(7,157)

110,976

105,363

(i) Exploration write offs relate to exploration wells that were plugged and abandoned as unsuccessful during the year.

(ii) Recoverability is dependent on the successful development and commercial exploration or sale of the respective areas of interest.

Notes to the Financial StatementFor the year ended 30 June 2016
18. Trade and other payables

Trade payables (i)

Accruals

Related party payables – joint arrangements (ii)

(i) Trade and other payables are non-interest bearing and are normally settled on 30-90 day terms.

(ii) Related party payables are accrued expenditure incurred on joint arrangements.

19. Provisions

Current Liabilities

Restoration provision

Exit penalty provision

Employee provisions

Other provisions

Non-Current Liabilities

Long service leave provision

Restoration provision(s)

Movement in carrying amount of the non-current restoration provision:-

Carrying amount at 1 July

Revaluation of provision

Provision through asset acquisition

Increase through accretion

Carrying amount at 30 June

Consolidated

2016
$’000

489

2,505

2,994

5,020

8,014

2015
$’000

1,400

3,636

5,036

3,900

8,936

Consolidated

2016
$’000

2015
$’000

1,500

3,663

401

391

4,064

1,913

346

145

65,202

45,049

65,548

45,194

45,049

41,256

(670)

(5,772)

19,424

1,399

8,132

1,433

65,202

45,049

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 2016 equalled 2.12% (2015: 2.98%) reflecting the Australian
Government 10 year bond rate.

Notes to the Financial StatementFor the year ended 30 June 201620. 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

2016
$’000

3,059

2015
$’000

3,066

(19)

4,004

310

(1,248)

3,059

3,066

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 acquired on 7 May 2014.

The discount rate used in the calculation of the liability as at 30 June 2016 equalled 2.12% (2015: 2.98%) 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 $21.7 million (net of costs and tax of $0.6 million) through an
institutional placement and a share purchase plan, 101.0 million new ordinary shares were issued.

Fully paid ordinary shares carry one vote per share and carry the right to dividends.

Consolidated

2016
$’000

2015
$’000

137,558

115,460

2016

2015

Thousands

$’000

Thousands

$’000

331,905

115,460

329,236

114,625

101,047

21,650

835

Movement in ordinary shares on issue

At 1 July 2015

Equity issue

Issuance of shares for Performance Rights

2,234

448

2,669

At 30 June 2016

435,186

137,558

331,905

115,460

Notes to the Financial StatementFor the year ended 30 June 201621. Contributed equity and reserves continued

Reserves

Consolidated

Foreign
currency
translation
reserve
$’000

Share
based
payment
reserve
$’000

Option
premium
reserve
$’000

Available
for sale
investment
reserve
$’000

Cash flow
hedge
reserve

Equity
instrument
reserve

$’000

Consolidation
reserve
$’000

At 30 June 2014

(541)

(164)

4,978

3,142

Other comprehensive
income/(expenditure)

Transferred to issued
capital

Share-based payments

At 30 June 2015

(541)

Other comprehensive
income/(expenditure)

Transferred to issued
capital

Share-based payments

1,059

895

237

(835)

1,629

5,772

(448)

1,884

At 30 June 2016

(541)

1,132

7,208

(3,142)

Nature and purpose of reserves

Consolidation reserve

Total
$’000

7,440

(2,083)

(835)

1,629

6,151

(700)

(553)

(1,016)

(448)

1,884

(700)

(553)

6,571

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 an Australian dollar loan and the 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 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.

Available for sale investment 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.

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.

Notes to the Financial StatementFor the year ended 30 June 2016

21. Contributed equity and reserves continued

(Accumulated Losses) / Retained earnings

Movement in (accumulated losses) / retained earnings were as follows:-

Balance at 1July

Net loss for the year

Balance at 30 June

Capital Management

Consolidated

2016
$’000

2015
$’000

(17,740)

45,728

(34,839)

(63,468)

(52,579)

(17,740)

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, or
issue new shares. No changes were made in the objectives, policies or processes during the years ended 30 June 2016 and 30 June 2015.

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 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.

Notes to the Financial StatementFor the year ended 30 June 201622. 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 2016:-

Consolidated

Financial assets

Available for sale investments

Equity instruments at fair value through other
comprehensive income

Financial liabilities

Success fee financial liability

Derivative financial instruments

Carrying amount

Fair value

Level

2016
$’000

2015
$’000

2016
$’000

2015
$’000

1,343

790

3,059

1,275

3,066

3,059

1,275

3,066

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:-

Available for sale investments
The fair value of available for sale investments 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.

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.

On adoption of AASB 9 the Group’s available for sale investments were reclassified as equity instruments. Refer to Note 23 for further
information on the early adoption of AASB 9.

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 includes: a probability of 37% that no payment is made and a probability of 63% the payment is
made in 2021. The discount rate used in the calculation of the liability as at 30 June 2016 equalled 2.12% (June 2015: 2.98%).

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 2016 and 30 June 2015.

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 2016 and 30 June 2015.

a) Foreign currency risk
The Group has transactional currency exposure arising from all its sales which are denominated in United States dollars, whilst almost all
its costs are denominated in the Group’s functional currency of Australian dollars.

In addition the Group operates internationally and is exposed to foreign exchange risk arising from various currency exposures, to the
United States dollars and Euros. Transaction exposures, where possible, are netted off across the Group to reduce volatility and provide a
natural hedge.

Notes to the Financial StatementFor the year ended 30 June 2016
22. Financial risk management objectives and policies continued

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.

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

2016
$’000

2015
$’000

7,045

3,198

4,016

6,360

282

1,265

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

2016
$’000

(987)

1,206

2015
$’000

(758)

926

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 2016 of
$2,953,605 (2015: $5,009,182).

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%

Impact on after tax profit

2016
$’000

339

(339)

2015
$’000

537

(537)

c) Interest rate risk

The Group has no borrowings at 30 June 2016 (2015: $ 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 $32,902,000 (2015: $31,993,000).

If the interest rate were 1% rate higher at the balance date

If the interest rate were 1% rate lower at the balance date

Impact on after tax profit

2016
$’000

(24)

2015
$’000

(46)

Notes to the Financial StatementFor the year ended 30 June 201622. 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 weekly basis including cash flow forecasts to
determine the forecast liquidity position and maintain appropriate liquidity levels.

Trade and other payables amounting to $8,581,000 (2015: $8,936,000) 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. Early adoption of AASB 9

Impact on revaluation reserve

Impact on profit before tax

2016
$’000

(79)

2015
$’000

134

2016
$’000

2015
$’000

(134)

As at 1 July 2015, Cooper Energy early adopted AASB 9 Financial Instruments (2014). The early adoption of AASB 9 has been applied
from 1 July 2015. In line with the transition requirements, comparatives are not restated.

Changes to classification and measurement of financial assets and financial liabilities

The adoption of AASB 9 has resulted in amendments to the measurement and classification requirements for financial instruments
previously accounted for under AASB 139 Financial Instruments: Recognition and Measurement.

Under AASB 9 an entity classifies its financial assets as subsequently measured at either amortised cost or fair value. An election can
be made to designate a financial asset as measured at fair value through profit or loss on initial recognition if this significantly reduces
an accounting mismatch. The designation at fair value through profit or loss is irrevocable. The standard also allows an entity to make
an irrevocable election at initial recognition of particular investments in equity instruments to be measured at fair value through other
comprehensive income with no recycling through profit or loss. On adopting the new standard, the classification of the Group’s available
for sale financial assets has changed to fair value through other comprehensive income, as outlined in the table below.

The requirements in AASB 139 regarding classification and measurement of financial liabilities have been retained, including the related
application and implementation guidance. Financial liabilities continue to be measured at either fair value through profit or loss or
amortised cost. The criteria for designating a financial liability at fair value through profit or loss also remain unchanged.

Hedge accounting

AASB 9 aligns hedge accounting more closely with common risk management practices.

The key components of the standard are as follows:-

• Risk components that are separately identifiable and reliably measurable will be eligible as hedged items, including non-financial items.

• Effectiveness measurement testing is required only on a prospective basis. New hedge effectiveness criteria include existence of an

economic relationship between the hedged item and the hedging instrument.

• Certain requirements must be met for discontinuing a hedge relationship. Changes to the hedge relationship may result in rebalancing

of the hedge ratio rather than de-designation.

Notes to the Financial StatementFor the year ended 30 June 201623. Early adoption of AASB 9 continued

Derivative financial instruments for which the Group elects to adopt hedge accounting will be accounted for at fair value through other
comprehensive income. Hedge ineffectiveness will be recognised in profit or loss.

Impacts of early adoption of AASB 9

The table below shows the change in classification and measurement category of the Group’s financial instruments on early adoption
of AASB 9.

AASB 139 (previous)
classification of
financial instrument

AAB 9 (current)
classification of
financial instrument

Cash and cash equivalents

Term deposits

AASB 139 (previous)
measurement
category

AASB 9 (current)
measurement
category

Amortised cost

Available for sale investments

Equity instruments at fair value
through OCI

Fair value through OCI
(recycled through P&L)

Fair value through OCI
(not recycled through P&L)

Trade and other receivables

Amortised cost

Derivative financial instruments

Fair value through P&L

Trade and other payables

Amortised cost

Success fee financial liability

Fair value through P&L

Impairment impact

AASB 9 also requires impairment on financial assets to be assessed under the lifetime expected credit loss model. This change has no
impact on the Group.

It is noted that there is no change in the carrying amount of any of the Group’s financial instruments under AASB 9 and AASB 139.
In addition to the accounting treatment for hedges, AASB 9 also requires that the Group’s listed investments are classified as equity
instruments at fair value through other comprehensive income with fair value movements remaining within equity and not being recycled
through profit or loss.

The adoption of AASB 9 does not have any material impact of the Group’s financial information and comparatives have not been restated.

24. Hedge accounting

The Group 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, 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 60% of the
Group’s total expected sales in US dollars to June 2017 and reducing percentages thereafter.

Oil price cash flow hedges outstanding at 30 June 2016:-

• A$57.00-69.70 collar options for 10,000 bbls/month for the period July 2016 to December 2016 decreasing to 5,000 bbls/month for

the period January 2017 to June 2017.

• A$54.45 50% participating swaps for 5,000 bbls/month for the period July 2016 to December 2017.

The table below shows the Group’s hedges that are currently outstanding.

Hedge arrangements (bbls remaining)

A$57.00-69.70 collar options

A454.45 – 50% participating swap

Total

FY17H1

60,000

30,000

90,000

FY17H2

FY18H1

30,000

60,000

30,000

Total

90,000

180,000

These transactions have been entered into in order to reduce the variability of cash flows arising from oil sales during the period July 2016
to December 2017. The impact of these transactions is that the Group has locked in an average floor price of $55.98/bbl while still being
able to participate in upside should the oil price increase.

Notes to the Financial StatementFor the year ended 30 June 2016
24. Hedge accounting continued

The fair value of the options vary based on the level of sales and changes in forward rates.

Fair value of oil price options

2016

2015

Assets
$’000

Liabilities
$’000

1,275

Assets
$’000

Liabilities
$’000

The terms of the oil price options match the terms of the expected highly probably forecast sales other than being Australian dollar
denominated options and the forecast sales being in US dollars. This does expose the Group to some ineffectiveness required to be
recognised in the income statement – a non-cash expense of $0.3 million has been recognised as hedge ineffectiveness for the period
ending 30 June 2016.

During the financial year, $2.5 million was reclassified from 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 $1.0 million and a tax
benefit of $0.3 million relating to the hedging instruments, is included in OCI.

The amounts retained in OCI at 30 June 2016 are expected to mature and affect the statement of profit or loss in 2017.

25. 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

Consolidated

2016
$’000

2015
$’000

322

248

570

357

582

939

The Parent entity leases a suite of offices in Adelaide from which it conducts its operations. The lease is for a further four years with an
option to renew after that date.

Exploration capital commitments not provided 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

5,405

2,200

44,597

12,359

7,605

56,956

Cooper Energy elected not to participate in the most recent extension of the Hammamet Permit in Tunisia and has provided the joint
venture partners with a notice of withdrawal from the Hammamet Joint Venture. The terms of withdrawal have not been finalised with the
remaining joint venture partners, however it is Cooper Energy’s view that it does not have any further work commitments connected with
the permit, notwithstanding that the permit has been extended and work commitments for the joint venture remain in place.

The remaining joint venture parties have submitted a request for arbitration in the London International Court of Arbitration claiming
security for Cooper Energy’s share of drilling a well which they assert is at least US$13.1 million (plus an unquantified claim for damages
for breach of contract). Cooper Energy denies any liability and is defending the claim.

As at 30 June 2016 the Parent entity has bank guarantees for $161,512 (2015: $4,067,000). These guarantees are in relation to
performance bonds on exploration permits and guarantees on office leases.

Notes to the Financial StatementFor the year ended 30 June 201626. 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

Ownership Interest

2016

2015

Australia

PEL 186

VIC/RL 13-15

Indonesia

Oil and gas exploration

Oil and gas exploration and production

- 1

33.33%

100% 2

65%

Tangai-Sukananti KSO

Oil and gas exploration and production

Sumbagsel PSC

Merangin III PSC

Tunisia

Oil and gas exploration

Bargou Exploration Permit

Oil and gas exploration

Nabeul Exploration Permit

Oil and gas exploration

b) Joint Arrangements in which Cooper Energy Limited is not the operator/manager

55%

- 3

30%

- 4

55%

100%

30%

85%

Australia

PEL 90K

PEL 93*

PEL 100

Oil and gas exploration

Oil and gas exploration and production

Oil and gas exploration

25%

30%

25%

30%

19.167%

PRL 183-190 (Formerly PEL 110)

Oil and gas exploration

PEL 494

PEL 495

PEP 150

PEP 168

PEP 171

PEP 151

PRL 32

Oil and gas exploration

PRL 85-104* (Formerly PEL 92)

Oil and gas exploration and production

VIC/RL 3

Oil and gas exploration and production

Orbost gas plant

Gas production

Tunisia

20%

30%

- 5

20%

50%

25%

- 1

30%

25%

50%

20%

30%

20%

50%

25%

75%

30%

25%

50%

Hammamet Exploration Permit

Oil and gas exploration

- 4

35%

*Includes associated PPL’s

1 Exited during period
2 On 26 May 2016 Beach Energy assigned its interest in VIC/RL 13-15 to Cooper Energy at which point Cooper Energy’s interest in the

permits increased to 100%. Beach Energy’s withdrawal will have an effective date of 27 October 2016 in accordance with the terms of
the Deed of Withdrawal.

3 Sale of Indonesian exploration permits during the 2016 financial year
4 Exited during period. Refer to Note 25 commitments and contingencies for further information
5 PEL 495 was amalgamated with PEL 494 on 28 September 2015

Notes to the Financial StatementFor the year ended 30 June 201627. Related parties

The Group has a related party relationship with its subsidiaries, joint arrangements (see Note 26) 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.

Executive Directors

Mr D. P. Maxwell

Mr H. M. Gordon

Non-Executive Directors

Mr J. Conde AO (Chairman)

Mr J. W. Schneider

Ms A. Williams

Executives at year end

Mr J. de Ross (Chief Financial Officer and Company Secretary)

Ms A. Evans (Company Secretary and Legal Counsel)

Mr I. MacDougall (Operations Manager)

Mr A. Thomas (Exploration Manager)

Mr E. Glavas (Commercial and Business Development Manager)

The key management personnels’ remuneration included in General Administration (see Note 4) are as follows:-

Short-term benefits

Post-employment benefits

Performance Rights and Share Appreciation Rights

Total

Consolidated

2016
$

2015
$

3,550,762

3,983,833

163,750

160,281

1,361,363

1,129,020

5,075,875

5,273,134

100

Notes to the Financial StatementFor the year ended 30 June 2016

27. Related parties continued

Subsidiaries

The Group financial statements include the financial statements of Cooper Energy Limited and the subsidiaries listed in the following table.

Name

Cooper Energy Indonesia Limited

Cooper Energy Sukananti Limited

Cooper Energy Sumbagsel Limited

Cooper Energy Merangin III 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

Cooper Energy (PBGP) Pty Ltd

CE Poland Coopertief UA

CE Polska sp z.o.o.

Joint arrangements

Country of
incorporation

British Virgin Islands

Australia

Netherlands

Poland

Equity interest

2016
%

100

2015
%

100

During the reporting period, the Group provided geological and technical services to joint arrangements it manages at a cost of
$1,746,000 (2015: $2,822,000). At the end of the financial period, $77,800 was outstanding for these services (2015: $391,000).

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.

101

Notes to the Financial StatementFor the year ended 30 June 2016
28. Share based payment plans

On 12 November 2015 shareholders of Cooper Energy approved a new Equity Incentive Plan (EIP).

During the financial year, issues were made in December 2015. The performance rights and share appreciation rights were issued for no
consideration. The right extends to the holder of the right to be vested with 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
prorata calculation. If Cooper Energy is ranked 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

7,892,812

$0.175

The number of performance rights and share appreciation rights held by employees is as follows:-

Balance at beginning of year

- granted

- vested

- expired and not exercised

- forfeited following employee resignation

Balance at end of year

Achieved at end of year

Number of Share
appreciation rights

Number of
performance rights

2016

22,278,100

7,892,812

22,278,100

7,892,812

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.

102

Notes to the Financial StatementFor the year ended 30 June 2016

28. Share based payment plans continued

Share Appreciation Rights Fair value assumptions

15 December 2015

Fair value at measurement date

Share price

Risk free interest rate

Expected volatility

Dividend yield

6.2 cents

17.5 cents

1.95%

50%

Performance Rights Fair value assumptions

15 December 2015

Fair value at measurement date

Share price

Risk free interest rate

Expected volatility

Dividend yield

13.1 cents

16.5 cents

2.13%

53%

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.

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 rights 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

6 November 2013

28 April 2014

1 December 2014

Number of
rights granted

6,581,999

312,033

6,584,708

Average share price
at commencement
date of grant

Average contractual
life of rights at
grant date in years

Remaining life of
rights in years

$0.405

$0.510

$0.285

103

Notes to the Financial StatementFor the year ended 30 June 201628. Share based payment plans continued

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 resignation

Balance at end of year

Achieved at end of year

Number of rights
2016

Number of rights
2015

17,276,975

14,748,003

6,584,708

(2,234,300)

(2,669,814)

(2,920,525)

(223,478)

(955,080)

(1,162,444)

11,167,070

17,276,975

3,017,074

1,746,390

The weighted average price of shares vested during the financial year was $0.20 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

Fair value assumptions

Fair value at measurement date

Share price

Risk free interest rate

Expected volatility

Dividend yield

Fair value assumptions

Fair value at measurement date

Share price

Risk free interest rate

Expected volatility

Dividend yield

104

6 November 2013

31.2 cents

40.5 cents

2.82%

48%

28 April 2014

36.0 cents

51.0 cents

2.72%

49%

1 December 2014

19.4 cents

28.5 cents

2.35%

51%

Notes to the Financial StatementFor the year ended 30 June 2016

29. 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

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

30. 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

31. Events after the reporting period

There are no significant events subsequent to 30 June 2016 at the date of this report.

Consolidated

2016
$

2015
$

172,914

183,120

18,540

191,454

183,120

191,454

183,120

Parent Entity

2016
$’000

2015
$’000

52,613

45,939

202,061

173,462

9,633

8,179

80,400

61,323

137,558

115,460

(21,878)

(9,119)

(700)

(553)

7,209

5,773

121,661

112,139

(12,759)

(54,287)

(1,253)

(3,260)

322

245

567

357

582

939

105

Notes to the Financial StatementFor the year ended 30 June 2016Directors’ 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 2016 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 2016.

Signed is accordance with a resolution of the Directors.

Mr John C. Conde AO
Chairman

15 August 2016

Mr David P. Maxwell
Director

106

Ernst & Young
121 King William Street
Adelaide SA 5000 Australia
GPO Box 1271 Adelaide SA 5001

Tel: +61 8 8417 1600
Fax: +61 8 8417 1775
ey.com/au

Independent auditor’s report to the members of Cooper Energy
Limited

Report on the financial report

We have audited the accompanying financial report of Cooper Energy Limited, which comprises the consolidated
statement of financial position as at 30 June 2016, 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 comprising a summary of significant accounting policies and other explanatory information, and the
directors' declaration of the consolidated entity comprising the company and the entities it controlled at the
year's end or from time to time during the financial year.

Directors' responsibility 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
controls as the directors determine are necessary to enable the preparation of the financial report that is free
from material misstatement, whether due to fraud or error. In note 2b, the directors also state, in accordance
with Accounting Standard AASB 101 Presentation of Financial Statements, that the financial statements comply
with International Financial Reporting Standards.

Auditor's responsibility

Our responsibility is to express an opinion on the financial report based on our audit. We conducted our audit in
accordance with Australian Auditing Standards. Those standards require that we comply with relevant ethical
requirements relating to audit engagements and plan and perform the audit to obtain reasonable assurance about
whether the financial report is free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the
financial report. The procedures selected depend on the auditor's judgment, including the assessment of the risks
of material misstatement of the financial report, whether due to fraud or error. In making those risk assessments,
the auditor considers internal controls relevant to the entity's preparation and fair presentation of the financial
report 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 controls. An audit also includes evaluating the
appropriateness of accounting policies used and the reasonableness of accounting estimates made by the
directors, as well as evaluating the overall presentation of the financial report.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit
opinion.

Independence

In conducting our audit we have complied with the independence requirements of the
Corporations Act 2001
have given to the directors of the company a written Auditor’s Independence Declaration, a copy of which is
included in the directors’ report.

. We

A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation

107

Opinion

In our opinion:

the financial report of Cooper Energy Limited is in accordance with the Corporations Act 2001,
including:

giving a true and fair view of the consolidated entity's financial position as at 30 June 2016 and of
its performance for the year ended on that date; and

ii.

complying with Australian Accounting Standards and the Corporations Regulations 2001; and

the financial report also complies with International Financial Reporting Standards as disclosed in note
2b.

Report on the remuneration report

We have audited the Remuneration Report included in pages 37 to 51 of the directors' report for the year ended
30 June 2016. 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.

Opinion

In our opinion, the Remuneration Report of Cooper Energy Limited for the year ended 30 June 2016, complies
with section 300A of the Corporations Act 2001.

Ernst & Young

L A Carr
Partner
Adelaide
15 August 2016

A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation

108

Ernst & Young
121 King William Street
Adelaide SA 5000 Australia
GPO Box 1271 Adelaide SA 5001

Tel: +61 8 8417 1600
Fax: +61 8 8417 1775
ey.com/au

Auditor’s independence declaration to the Directors of Cooper Energy
Limited

As lead auditor for the review of Cooper Energy Limited for the year ended 30 June 2016, I declare to the best of
my knowledge and belief, there have been:

a) no contraventions of the auditor independence requirements of the

Corporations Act 2001

in relation to

the review; and

b) no contraventions of any applicable code of professional conduct in relation to the review.

This declaration is in respect of Cooper Energy Limited and the entities it controlled during the financial period.

Ernst & Young

L A Carr
Partner
Adelaide
15 August 2016

A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation

109

Securities Exchange and Shareholder Information
as at 31 August 2016

Listing
The company’s shares are quoted on the Australian Securities Exchange under the code of “COE”.

Number of Shareholders
There were 4,846 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 2016)

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

Number of Shares

% of issued capital

1,020

1,240

735

1,611

240

4,846

275,075

3,618,310

6,101,247

55,593,839

369,597,658

435,186,129

0.06

0.83

1.40

12.77

84.93

100.00

Number of Holders of Performance Rights

Total Rights

19,059,882 Performance Rights

22,278,100 Share Appreciation Rights

Unmarketable Parcels
There were 1,268 members, representing 603,708 shares, holding less than a marketable parcel of 1,640 shares in the company.

Twenty Largest Shareholders

Rank Name

10.

11.

12.

13.

14.

15.

16.

17.

18.

19.

20.

J P Morgan Nominees Australia Limited

Beach Energy Limited

Citicorp Nominees Pty Limited

HSBC Custody Nominees (Australia) Limited

National Nominees Limited

Zero Nominees Pty Ltd

Citicorp Nominees Pty Limited

BNP Paribas Noms Pty Ltd

Kavel Pty Ltd

HSBC Custody Nominees (Australia ) Limited - A/C 2

HSBC Custody Nominees (Australia) Limited - GSCO ECA

Nero Resource Fund Pty Ltd

Invia Custodian Pty Ltd

Rocket Science Pty Ltd

Mr Timothy Bryce Kleemann

Bresrim Nominees Pty Ltd

Vanez Holdings Pty Ltd

Celtic Trust Company Ltd

Town Inns (Holdings) Pty Ltd

Units

% of Issued Capital

88,791,150

60,590,884

36,737,325

32,641,939

23,053,429

22,551,753

9,043,912

7,069,253

3,220,101

3,079,100

3,004,632

2,500,000

2,348,400

2,250,687

1,827,274

1,725,284

1,610,970

1,350,000

1,329,281

1,322,728

20.40

13.92

8.44

7.50

5.30

5.18

2.08

1.62

0.74

0.71

0.69

0.57

0.54

0.52

0.42

0.40

0.37

0.31

0.30

Totals: Top 20 holders of Ordinary Fully Paid Shares (Total)

306,048,102

70.32

Substantial Shareholder
The following were substantial holders in the company, as disclosed in substantial holding notices given to the Company as required by
section 671B of the Corporations Act.

Name of entity

Beach Energy Limited

Kinetic Investment Partners Limited

CBA

Westoz Funds Management

110

Number of securities in which substantial shareholder
has a relevant interest as at date of last notice

Voting power
as at date of last notice

60,590,884

20,924,029

26,397,795

16,738,808

14.52%

7.15%

6.32%

5.02%

Shareholder Information

Share Registry

Annual Report mailing list

Shareholders who wish to vary their annual
report mailing arrangements should
advise Computershare in writing. Electronic
versions of the report are available to all
via the company’s website. Annual Reports
will be mailed to all shareholders who
have elected to be placed on the mailing list
for this document. Report election
forms can be downloaded from the
Computershare website.

Forms for download

All forms relating to amendment of
holding details and holder instructions
to the company are available for
download from the Computershare.

Investor information

Information about the company is available
from a number of sources:

• Website: www.cooperenergy.com.au

• E-news: Shareholders can nominate

to receive company information
electronically. This service is hosted
by Computershare and can be accessed
via Computershare’s website

• Publications: the annual report is the
major printed source of company
information. Other publications include
the half-yearly report, company press
releases, investor packs, presentations
and Open Briefings. All publications can
be obtained either through the company’s
website or by contacting the company

• Telephone or email enquiry:

to Don Murchland, Investor Relations
+61 439 300 932;
donm@cooperenergy.com.au

Computershare Investor Services Pty Ltd
Level 5, 115 Grenfell Street
Adelaide SA 5000

Website: investorcentre.com/au

Telephone:

Australia 1300 655 248
International +61 3 9415 4887

Facsimile: +61 3 9473 2500

Enquiries and share registry
address

Shareholders with enquiries about
their shareholdings should contact the
company’s share registry, Computershare
Investor Services Pty Ltd, via the telephone
contact above.

Online shareholder
information

Shareholders can obtain information
about their holdings or view their
account instructions online, as well as
download forms to update their holder
details. For identification and security
purposes, you will need to know your
Holder Identification Number (HIN/SRN),
Surname/Company Name and Post/
Country Code to access. This service is
accessible via the Computershare website.

Change of address

Shareholders who have changed their
address should advise Computershare
in writing. Written notification can be
mailed or faxed to Computershare at the
address given above and must include
both old and new addresses and the
security holder reference number (SRN)
of the holding.

Change of address forms are available
for download from the Computershare
website. Alternatively, holders can amend
their details on-line via the Computershare
website. Shareholders who have broker
sponsored holdings should contact their
broker to update these details.

111

Notes

112

Corporate Directory

Directors

John C Conde AO, Chairman
David P Maxwell
Hector M Gordon
Jeffrey W Schneider
Alice J M Williams

Company Secretaries

Alison M Evans
Jason de Ross

Registered Office and Business Address

Level 10, 60 Waymouth Street
Adelaide, South Australia 5000

Telephone: + 618 8100 4900
Facsimile: + 618 8100 4997
E-mail: customerservice@cooperenergy.com.au
Website: www.cooperenergy.com.au

Auditors

Ernst & Young
121 King William Street
Adelaide, South Australia, 5000

Solicitors

Johnson Winter & Slattery
Level 9, 211 Victoria Square
Adelaide SA 5000

Bankers

Westpac Banking Corporation
Level 18, 91 King William Street
Adelaide, South Australia, 5000

National Australia Bank Limited
Level 2, 22 King William Street
Adelaide, South Australia, 5000

Commonwealth Bank of Australia
Level 8, 100 King William Street
Adelaide, South Australia, 5000

Citibank N.A.
2 Park Street
Sydney, New South Wales 2000

Share Registry

Computershare Investor Services Pty Limited
Level 5, 115 Grenfell Street
Adelaide SA 5000

Website: investorcentre.com/au

Telephone:
Australia 1300 655 248
International +61 3 9415 4887
Facsimile: +61 3 9473 2500