51Talk Online Education Group Annual Report 2015

FY2015 Annual Report · 51Talk Online Education Group

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Front cover:

The Sole and Manta gas fields in the Gippsland Basin offshore Victoria hold
2C Contingent Resources totalling 317 PJ of gas, offering eastern Australian gas
customers a competitive supply source from 2019. Cooper Energy is working to
commercialise these fields for supply via the Orbost Gas Plant in which it holds
a 50% interest.

Cooper Energy Limited
ABN 93 096 170 295

Reporting Period,
Terms and Abbreviations

Annual Report

This document has been prepared to
provide shareholders with an overview of
Cooper Energy Limited’s performance
for the 2015 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 2015 Annual General Meeting of
Cooper Energy Limited ABN 93 096 170 295
(Company) will be held at 10.30 am
(Australian Central Daylight Saving Time)
on Thursday, 12 November 2015 in the
PwC Building, Level 11, 70 Franklin Street,
Adelaide, South Australia.

A formal Notice of Meeting has been
mailed to shareholders. Additional copies
can be obtained from the Company’s
registered office or downloaded from its
website at www.cooperenergy.com.au

Abbreviations and terms

Reserves and resources

This report uses terms and abbreviations
relevant to the company, its 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 “2015”,
FY15 or “2015 financial year” refer to
the 12 months ended 30 June 2015
unless otherwise stated. References to
“2014”, FY14 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

km: kilometres

P & A: plugged & abandoned

PJ: petajoules

1C: Low Estimate

2C: Best Estimate

3C: High Estimate

1P: Proved Reserves

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.

2P Reserves: Proved & Probable Reserves

Rounding

3P: Proved, Probable & Possible Reserves

MMbbl: million barrels of oil

MMboe: million barrels of oil equivalent

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 presented.

Cooper Energy
finds, develops and
commercialises
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 Cooper Basin

and Indonesia

• gas projects and resources positioned to supply eastern

Australia’s gas needs

• a management team and board with proven success in
exploration, gas commercialisation, production and
building resource companies

Key figures:

For the year ended 30 June 2015

Production:

Average oil price:

475,000 barrels of oil

A$85.48 per barrel

Average production cost:

A$36.60 per barrel

Net (debt)/cash:*

2P Reserves:

$39.4 million

3.1 million barrels

Contingent Resources:*

58.4 million boe

Shares on issue:*

*as at 30 June 2015

331.9 million

Our key results for
2015 were:

A statutory loss after tax of $(63.5) million.

Revenue and balance sheet valuations were affected by a
31% drop in average oil price.

2P Reserves increased 53% and 2C Contingent Resources increased 66%.
Proved and Probable Reserves of 3.1 million barrels and 2C Contingent
Resources of 58 million boe are the company’s highest yet.

The foundation for a gas business was put in place.

Gas resources and processing plant were acquired, heads
of agreement for gas supply negotiated and project engineering
and design commenced.

Financial results

Sales revenue down 46% to $39.1 million

Statutory loss after tax of $(63.5) million, down from $22.0 million

Underlying loss after tax of $(1.3) million down from $25.3 million

Cash and investments at 30 June of $41.3 million

Exploration and production

Proved and Probable Reserves of 3.1 million boe

2C Contingent Resources of 58.4 million boe, up from 35.1 million boe

Oil production of 0.48 million barrels with average cost of $36.60/barrel

Portfolio management and development

Acquisition of 50% interest in Sole gas field and Orbost Gas Plant

Sole Gas Project into FEED

BMG Business Case completed, identifies the Manta gas opportunity

Sales Revenue
$ million

2P Reserves
million barrels of oil

2C Contingent Resources
million boe

72.3

3.1

58.4

39.1

2.0

35.1

2014

2015

2014

2015

2014

2015

Chairman’s Report
John Conde AO

The results and year-end position documented in this report are
typical of the juxtaposition of short term returns and sustainable
value creation that often occurs in growing resource companies
and can try the patience of shareholders.

On one hand, the year-end Reserves and
Resources are the highest ever recorded by
Cooper Energy. Oil reserves are 53% higher
than at the beginning of the year and the
company has increased its 2C Contingent
Resource of gas 62% from 78 PJ to 204 PJ.
In contrast, the profit and total shareholder return
are the lowest recorded by the company and
market capitalisation at year-end of $81 million
was just under half the corresponding figure
of $166 million twelve months earlier.

In presenting the 2015 Annual Report, I would
like to address this disconnect between the
year’s financial results and market valuation of
your company and its Reserves, Resources
and opportunities.

Cooper Energy’s 2015 financial results, like its
peers, bear witness to the impact of the year’s
lower oil price on revenue, profit and balance
sheet valuations.

Price volatility is an inherent feature of
commodity markets and variation between
periods is the norm. However, in 2015 oil prices
were not only the lowest for several years, but
the price movement was particularly severe.
Cooper Energy’s average price of A$85.48 per
barrel was the lowest received by the company
in 9 years. Moreover, this price was 31% lower
than the previous year’s figure, the largest annual
decline in the company’s 13 year history. This
substantial price change brought substantial
adjustments to profitability, balance sheet
valuations and investor sentiment across the oil
and gas sector.

In Cooper Energy’s case, the statutory loss of
$(63.5) million for the 12 months to June
2015 was recorded after significant items of

$(62.2) million. The underlying loss prior to
significant items of $(1.3) million compares to
the previous year’s underlying profit after tax
of $25.3 million.

It is relevant to note that operations are still
cash positive; not only at the oil prices that
prevailed in 2015 but also at the lower prices
recorded since year end. This reinforces
the merit of the company’s strategy to focus
on production assets at the low end of
the cost curve. The surplus being generated
by our oil operations is being applied to
the company’s strategy of identifying and
developing additional low cost oil reserves
and establishing a gas business supplying
eastern Australia.

Both of these strategic objectives were met
in 2015. The growth in reserves and progress
in establishing the gas business were the
highlights and the most significant outcomes
of the year. Put simply, these outcomes mean
Cooper Energy has substantially increased
its stock of physical resources for future
revenue and profit generation.

The resources in hand, and their associated
development plans, provide the opportunity
to increase production and revenue several
times current levels in the coming four to six
years. Furthermore, the addition of the stable,
long term cash flows typically generated
by gas contracts will mitigate the impact of
oil price shocks such as was experienced
in 2015.

The Managing Director has outlined the
initiatives taken and the assets involved to
build this position in his report.

This position has been achieved with
relatively low capital outlay to date, through
a combination of long term vision, assiduous
analysis, patient execution and a respect for
shareholder capital.

Fulfilment of the company’s strategy will,
as the Managing Director outlines, require
further expenditure. The company has
evaluated the range of funding options
available to meet these future commitments.
The selection of funding options and timing
will be driven by the shareholder value
imperative that has informed its gas strategy
execution to date.

Ongoing review and management of the
company’s portfolio will remain an essential
element of this process so that resources
and efforts are concentrated on those assets
that are consistent with strategy and offer
the most attractive long term return on
shareholder funds.

The board has no doubt that the resources
in place, and projects in train, can deliver
a substantial and attractive return to
shareholders. Whilst first income from the
Gippsland Gas Projects could occur from
January 2019, it is expected that equity
market interest and valuation of the project
will rise as project milestones are met in
the intervening period.

Safety is an area where the year-on-year
trend was disappointing. It is the view
of your board that safety is an absolute,
not a relative, value: it is not acceptable
for a single person to be exposed to
injuries as a result of company operations.
We believe we have strengthened our
processes and safety systems to support this.

The increased recordable case frequency
rates in 2015 came at the same time as an
increased investment in management and
reporting of safety, particularly in Indonesia
where the large majority of ‘man-hours’
occur. Industry history shows that a rise in
reportable cases is a common corollary of
lifting awareness of safety and improving the
accessibility and effectiveness of reporting
systems. Nevertheless, improved awareness
must be translated into improved results and
the board is resolved this be realised.

Your company has concluded 2015 with
a much stronger asset base, and with
promising opportunities, notwithstanding the
impact of the oil price on financial results and
equity market valuations. The progression of
those opportunities through the milestones
of project definition, investment decision,
financing and commissioning represent an
exciting future for Cooper Energy and its
shareholders over the next few years.
I am confident that under the leadership
of David Maxwell, and with our senior
management team, we will be successful in
these opportunities. Your board is determined
that this position is translated into the best
value outcome for shareholders.

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

John Conde AO
Chairman

Orbost Gas Plant,
Gippsland Basin, Victoria

Managing Director’s Report
David Maxwell

This is the third annual report since Cooper Energy adopted a
new strategy whereby cash generated from its oil production
would be invested to establish a gas business so shareholders
could participate in the value creation anticipated from meeting
supply opportunities foreseen in eastern Australia from
2016 onwards.

At the time, the new strategy was a profound
change for a company which had no Australian
gas resources and had been applying the cash
flow from its Cooper Basin oil operations to fund
international exploration in diverse locations.
Apart from the restructuring of the portfolio this
necessitated, the change brought a heightened
emphasis on commercial and technical
fundamentals and sustainable total shareholder
returns, saw the relocation of the corporate
office and employment of a new management
team and the reconstitution of the board
of directors.

Our focus on conventional gas resources that
were then uneconomic, but located close to
existing gas operations, was somewhat out
of step with market trends at the time. Large
unconventional gas resources were attracting
funding and enthusiastic investor interest. This
meant that Cooper Energy, equipped with the
advantage of being an ‘early-mover’, was able to
secure the gas assets it had targeted at good
value for our shareholders.

Market context and strategy

As this report documents, the company’s
strategy execution has aligned with market
trends, which are transpiring as expected.
Contracted supply of gas to eastern Australia
remains well below forecast demand in the
region for the period from 2019 onwards.
Customer demand and price forecasts continue
to be supportive of the strategy and in line with
our forecasts. In this context, the company has
secured the gas resources, gas plant and first
Heads of Agreement for sales to establish a
gas business to meet the market opportunity.
Our strategic focus has now shifted from
resource acquisition to project maturation,
development and delivery.

Pleasingly, this has been achieved without
compromising the historical ‘engine room’ of the
business, our cash generating oil production.
Our production of 475,000 barrels in 2015 was
comparable with the company’s average for the
past 5 years and year-end oil reserves are the
highest yet for Cooper Energy.

The lower oil prices experienced since
September 2014 have been the major influence
on the financial results documented in this report
and, by far, the principal reason for the year’s
lower revenue, earnings, cash flow and asset
value impairments.

Cooper Energy’s oil production is cash
generating at current prices, with anticipated
FY16 operating costs, including transport and
royalties, of $A38 per barrel. Our efforts to
reduce production costs and all other costs in
our business without compromising our health,
safety, community and environmental standards
are ongoing. Low cost, cash generating, oil
production is a critical element of our business
model and the protection of this is discussed
further under the heading ‘2016 outlook’ at the
conclusion of this report.

Care

The company has two key requirements for
all of its activities and plans: that they deliver
sustainable, 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 key sustainability
related elements of our operations is provided on
page 21 of this report.

It is disappointing to report that one lost time
injury and a small number of recordable incidents
occurred in the financial year.

The company has been proactive in analysing the
root causes and implications of these incidents
to help avoid reoccurrence. Investment has
been increased in the establishment of culture
and continuous improvement systems that will
support our ultimate objective of zero incident-
zero injury operations.

Financial results

Analysis and discussion of the financial results
for the year is provided in the Operating and
Financial Review which commences on page
28. In essence, the 2015 profit comprises
two elements.

1. A statutory loss of $(63.5) million which

includes significant non-operating items of
$(62.2) million.

As detailed in the Operating and Financial
Review, the significant non-operating
items principally relate to: adjustments of
$(47.6) million before tax made to the
valuation of the Tunisian assets which are
the subject of a divestment process; and
impairments of $(14.6) million to the carrying
value of PPL 207, an oil producing asset
in the Cooper Basin and non-core acreage
in the Otway Basin.

2. An underlying (ie exclusive of significant

non-operating items) loss of $(1.3) million.
The year’s lower oil prices and volumes
reduced gross profit, which was $14.1 million
compared with $46.2 million in 2014.
Expenditure incurred to support the
development of the gas business resulted
in the small loss.

Balance sheet and finance

Detailed discussion on the balance sheet, cash
generation and movements for the year are
provided in the Operating and Financial Review.
As at 30 June the company held cash and
financial assets of $41.3 million. Financial
assets are supplemented by financial facilities
of $40 million, which are subject to conditions.

Reserves and exploration
A report on the year’s exploration and
development activities and Reserves and
Resources, has been provided by the
Executive Director – Exploration & Production,
Hector Gordon, commencing on page 12.

There are a number of items of significance
I highlight and comment upon.

First, action taken by the company to preserve
cash in the low oil price environment resulted
in the number of wells drilled and capital
expenditure being substantially below guidance
at the start of the year. Cooper Energy
participated in 9 wells and committed capital
expenditure of $27.4 million for the year,
which compares to the plan of 18 wells and
capital expenditure guidance of $40 million
originally announced.

Second, notwithstanding reduced capital
expenditure, the company recorded its highest
year-end Reserves and Resources results.
Proved and Probable Reserves rose by 53%
and 2C Contingent Resources rose by 66%.

The increase in Proved and Probable Reserves
is largely the outcome of low-risk drilling which
targeted potential identified in well-established
producing fields.

In Indonesia, the company continued its appraisal
and development program to address potential
identified in the Tangai-Sukananti KSO. Whilst
this program has delivered incremental gains
in previous years, the results of Bunian-3
during the year were transformational for the
Indonesian operations, leading to: reserves
in the Tangai-Sukananti KSO more than
trebling; a 147% rise in daily production; and
the identification of further potential. The
assessment of some of that potential was
addressed after year-end with the Bunian-4
appraisal/development well. Results of the well,
which was completed as an oil producer, are
currently being assessed.

In the Cooper Basin, a number of existing fields
have continued to outperform expectations.
The implications of this, and the successful
development drilling at Callawonga, resulted in
additions to reserves which replaced 120%
of the year’s production from its main producing
area, PRLs 85 -104. This was offset in part
by performance-based writedowns to the Worrior
field in PPL 207. Worrior accounted for 6% of
the company’s production from the Cooper Basin
for the year.

Managing Director’s Report
David Maxwell

Gippsland Basin gas projects

The progress of the company’s gas strategy
during the year means it is now positioned
to deliver on the objective of establishing a
significant gas business supplying eastern
Australian customers in the foreseeable future.

These events and achievements included:

- the acquisition of a 50% interest in the Sole

gas field in VIC RL/3 offshore Victoria.
Sole is an undeveloped gas field with
marketable quantities of gas that are assessed
to be economic at forecast gas prices. Santos
Limited is the Operator and other interest
holder in VIC RL/3. The Sole gas field was
assessed to hold gross Contingent Resources
of 211 PJ (2C) of gas.

- the acquisition of a 50% interest in the Orbost
Gas Plant, an onshore gas processing plant
connected to the Eastern Gas Pipeline which
links Victoria and New South Wales. The plant,
commissioned in 2003, previously processed
gas from the Patricia-Baleen and Longtom
gas fields. Santos Limited is the Operator and
other interest holder in the Orbost Gas Plant.

- commitment of the Sole Gas Project to

Front End Engineering and Design (FEED)
for a Final Investment Decision (FID) during
the September quarter of 2016. The FEED
process is focussing on a stand-alone
development, with gas transported by sub-sea
pipeline to the Orbost Gas Plant.

- completion of the BMG Business Case, with
the identification of an economic opportunity
for development of the Manta gas field, with
gas produced being exported to the Orbost
Gas Plant. Subsequent to year end, the
VIC/L26, L27 and L28 joint venture agreed
to progress appraisal planning and further
feasibility studies.

- subsequent to year-end, the signing of the first
sales agreement for gas from Sole, a Heads
of Agreement with O-I Australia.

In essence, the progress made means Cooper
Energy has two marketable and competitive gas
resources, Sole and Manta, plus equity in a gas
plant ideally placed to process gas from these or
other offshore Gippsland Basin fields, at a time
when gas supply to eastern Australia is forecast
to tighten and gas prices forecast to rise.

Successful passage through the stages of
project design and definition, construction and

development could see Sole producing gas from
the January quarter of 2019 and Manta from
the middle of the 2021 calendar year.

The immediate focus in the twelve months to
June 2016 will be the completion of Sole FEED,
securing further gas sales contracts and the
completion of feasibility studies and appraisal
well planning for the Manta gas opportunity.

Negotiation of heads of agreement for further
gas sales is currently in progress. It is expected
that this process will result in the large majority
of Cooper Energy’s share of Sole gas being the
subject of bankable contracts prior to FID.

Bank sourced project finance enabled by these
contracts is one of a number of funding options
expected to be available to Cooper Energy.
A detailed analysis of the funding options and
combinations available was completed during
the year and has provided the basis of a project
funding plan which is ready for implementation.

The company expects to announce definitive
estimates of project cost and proposed funding
structures for the Sole project prior to the FID in
the September quarter of 2016.

Portfolio

Management of the company’s portfolio is an
ongoing process to ensure it is exposed to, and
directing its resources to, those opportunities
expected to provide the best risk-weighted
return for shareholders. This is a long term,
ongoing process due to the time involved
in bidding for, and divesting, licences and
the discipline required for the protection of
shareholder funds.

In Cooper Energy’s case, this has meant
researching and acquiring assets that offer
competitive gas supply to eastern Australia and
the divesting or withdrawal from acreage that
does not align with our strategy.

In 2015, the addition of the Gippsland Basin
acreage VIC RL/3 and the Orbost Gas
Plant was the most significant change in
the company’s portfolio. These assets, when
combined with the nearby VIC /L26, L27, and
L28 acquired in 2014 mean that the company
is now one of the larger interest holders in the
region. In addition, the company is the major
shareholder in Bass Strait Oil Company Limited
(with a 22.6% interest) which holds acreage
adjacent to Cooper Energy’s interests.

Cooper Energy was not able to complete the
divestment of Tunisian acreage foreshadowed in
the previous year’s annual report. The collapse
in oil prices during the year effectively deferred
interest in offshore oil exploration acreage
transactions, a situation which was subsequently
compounded by geopolitical events in the region.
The divestment process has yet to generate
acceptable offers.

The company has been seeking to defer and
limit further capital expenditure on non-core
assets wherever feasible. Accordingly, Cooper
Energy did not extend the Nabeul permit which
has now expired and is continuing efforts to
divest and reduce commitments in the Bargou
and Hammamet permits as soon as practicable.

Human Resources

The company’s workforce is developing in line
with the needs of its strategy and asset base.

At year-end Cooper Energy employed 22 full
time equivalent (FTE) employees in Australia and
a further 50 persons internationally, principally
Indonesia, compared to 21 FTE in Australia and
47 internationally at the beginning of the year.

2016 Outlook

Prevailing oil prices are continuing to challenge
the returns of the petroleum exploration and
production sector and the interest and sentiment
it is afforded by the investment community.
Moreover, the flow-on effects of this on the
broader oil and gas sector’s capital expenditure
can also be expected to compromise the
availability of new projects to drive its growth in
the longer term.

Your company, however, is well placed to endure
these conditions and to emerge from the 2016
year with growth projects underway.

Cooper Energy has entered the new financial
year in a strong position, expecting stable or
slightly higher production and the achievement
of milestones which significantly advance
its gas business. Gas market conditions and
developments have continued to reinforce
the merits of the company’s strategy and the
prospects of its gas projects.

The company’s efforts in 2016 will essentially be
directed towards 3 broad objectives:

1) maintaining and optimising the returns

from near term production.

It is expected that production for the year
will fall within the range of 450,000 to
550,000 barrels, in line with historical trends.
This will include the drilling of exploration
and development wells in the Cooper Basin.

2) progressing the Gippsland Gas Projects.

For Sole, the completion of FEED and the

securing of gas contracts will enable project
definition for a Final Investment Decision in
the first half of the 2017 financial year, and
the finalisation of the most suitable funding
arrangements. The Manta gas project will
be conducting further feasibility studies and
analysis and planning for appraisal drilling that
may be required.

3) ensuring the company’s costs and

expenditure are ‘right-sized’ for a lower
oil price environment while retaining
the capacity to execute our longer
term growth projects and exploration
programs.

While the company’s cash operating cost is
within current prices, prudent management
dictates that our structures be ‘sea-worthy’ for
greater volatility and lower prices.

All costs and activities are being reviewed on
an ongoing basis. Costs and staffing levels
are subject to ongoing review and refinement
for appropriateness for prevailing oil prices
whilst ensuring that the resources necessary
for excellent project delivery are in place and
applied most efficiently.

The company maintains a hedging program
to manage downside exposure to oil price
volatility. Hedging is reviewed on an ongoing
basis and reported in our quarterly reports to
the ASX and other company announcements.

Cooper Energy is now very well placed to

deliver on the opportunities we have before
us to safely build sustainable shareholder
returns.

David Maxwell
Managing Director

Reserves & Resources

Cooper Energy’s 2P Reserves as at 30 June 2015 are assessed to be 3.1 million barrels of oil (MMbbl).
This represents an increase of 1.1 MMbbl from 30 June 2014, driven by reserve increases in the Bunian
and Callawonga fields, offset by production and a reduction of assessed reserves in the Patchawarra
Formation in the Worrior Field.

Petroleum Reserves at 30 June 2015 (MMbbl)

Category

Proved
(1P)

Proved & Probable
(2P)

Proved, Probable &
Possible (3P)

Australia

Indonesia

Total

Australia

Indonesia

Total

Australia

Indonesia

Total

Developed

Undeveloped

Total

0.84

0.22

1.06

0.62

0.30

0.92

1.46

0.52

1.97

1.16

0.22

1.38

1.02

0.68

1.70

2.18

0.90

3.08

1.48

0.26

1.74

1.61

1.47

3.08

3.09

1.73

4.82

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

Category

Reserves at 30 June 2014

FY15 Production

Revisions

Reserves at 30 June 2015

Proved
(1P)

0.85

0.48

1.60

1.97

Proved & Probable
(2P)

Proved, Probable &
Possible (3P)

2.01

0.48

1.54

3.08

3.42

0.48

1.87

4.82

Contingent Resources
2C Contingent Resources at 30 June 2015 are assessed to be 58.4 MMboe. This represents a
66% increase of 23.3 MMboe from 30 June 2014. The key revisions are the acquisition of the Sole
field and the re-evaluation of the Manta field that have added 20.4 MMboe in the Gippsland Basin
to 30 June 2015.

Contingent Resources at 30 June 2015 (MMboe)

Category

Oil

Gas

Total

Gas

Oil

Total

Gas

Oil

Total

MMbbl

MMboe

MMbbl

MMboe

MMbbl

MMboe

Australia

129.7

Indonesia

Tunisia

Total

2.7

1.1

8.6

25.0

197.0

1.3

8.9

1.7

5.6

0.9

1.7

132.3

12.5

35.2

204.3

5.2

2.3

16.1

23.6

38.8

2.6

17.0

58.4

259.3

3.4

18.5

281.2

8.5

4.8

36.3

49.6

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

Category

Australia

Indonesia

Tunisia

Resource at 30 June 2014

Revisions

Resource at 30 June 2015

18.0

20.7

38.8

0.0

2.6

17.0

0.0

17.0

53.0

5.4

39.5

97.9

Total

35.1

23.3

58.4

Notes on calculation of Reserves and Resources

Calculation of reserves and resources

- The approach for all reserve and resource calculations is consistent with the definitions and guidelines in the Society
of Petroleum Engineers (SPE) 2007 Petroleum Resources Management System (PRMS). The resource estimate
methodologies incorporate a range of uncertainty relating to each of the key reservoir input parameters to predict
the likely range of outcomes. Project and field totals are aggregated by arithmetic and probabilistic summation.
Aggregated 1P and 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

- The Cooper Basin totals comprise the probabilistically aggregated PEL 92 project fields and the arithmetic summation

of the Worrior project reserves. The total includes 0.05 MMbbl oil reserves used for field fuel. The Indonesia totals
include removal of non-shareable oil (NSO) and comprise the probabilistically aggregated Tangai-Sukananti KSO
project fields. Totals are derived by arithmetic summation.

Contingent Resources

- The Contingent Resource assessment includes resources in the Gippsland Basin, in PRLs 85-104 and PEL 90K in
the Cooper Basin, the Tangai-Sukananti KSO, Indonesia and in the Hammamet West field in the Bargou Permit and
Tazerka field in the Hammamet Permit, offshore Tunisia. The following assessments have been released to the ASX:
Basker field on 18 August 2014, Manta field on 16 July 2015, Sole field on 25 May 2015 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 Resource in the Sole field in VIC/RL3, Gippsland Basin, offshore Victoria, have been assessed by Santos
Limited as Operator and documented in the Operator’s Preliminary Field Development Plan (2013) and refreshed
in May 2015 as part of the pre-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 Oil Equivalent (MMboe).

- Contingent Resources in the Basker field in VIC/L26 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 Oil Equivalent (MMboe).

- Contingent Resources in the Manta field in VIC/L26, VIC/L27 and VIC/L28 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 Oil
Equivalent (MMboe).

- Contingent Resources in the 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

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, and 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

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, Gippsland

and South Sumatra basins.

Hector Gordon
Executive Director –
Exploration & Production

Highlights of the year’s activities were:

• Acquisition of 50% in interest in Sole gas field and Orbost

Gas Plant (Gippsland Basin);

• Completion of the BMG Business Case indicating that

development of Manta gas resource is economically feasible;

• Bunian-3 results increased reserves by 1.2 MMbbl in the

Callawonga oil field, Cooper
Basin, South Australia

Bunian oil field, Sumatra.

Production

Cooper Energy’s oil production for the year totalled 0.48 MMbbl, 83% of which was derived from the
company’s Cooper Basin tenements. This is a 19% decrease on the previous year, primarily as a result
of natural decline from the company’s Cooper Basin fields, partially 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

2014

0.54

0.05

0.59

Cooper Energy participated in the drilling of nine wells during the year, comprising four exploration wells
and five appraisal/development wells. None of the exploration wells were successful, although one
well, Akela-1, was cased and suspended to allow further evaluation and possible testing. Three of the
five appraisal/development wells were successful and included the discovery of a new oil pool in
the “K” Sandstone in the Bunian field and a significant reserves addition to the southern flank of the
Callawonga field.

Type

Area

Tenement

Exploration

Cooper Basin

ex PEL 92

Well

Shelly-1

ex PEL 92

Sensation-1

Appraisal

Cooper Basin

Development

Cooper Basin

PEL 100

PEL 110

PPL 247

PPL 249

PPL 220

Jenners-1

Akela-1

Perlubie-3

Elliston-2

Callawonga-10

Callawonga-11

South Sumatra

Tangai-Sukananti KSO

Bunian-3 ST2

1. Cased and suspended for potential further testing

2. Cased and suspended and subsequently completed as an oil production well

Result

P&A

Cased & Suspended 1

P&A

Oil Well 2

Review of Operations

139°20'

139°40'
39 0

-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

Oil well

Plugged and abandoned well

-28°

Sensation-1

Callawonga-10

Shelly-1

99
Callawonga
Callawonga-11
Windmill

100

Parsons
90
89
Perlubie-3

Butlers

Elliston-2

85
Perlubie
87

Sellicks

102

Christies

Silver Sands

Germein

101

104

103
Lycium Hub

PRLs 85 to 104 (25%) (ex ‘PEL 92’)

Plan area

TAS

58AR15
Cooper_58AR15

Cooper Basin
Cooper Energy holds interests in four
exploration licenses, twenty 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 79%
of Cooper Energy’s total production
in FY15. Oil exploration is also
being undertaken in the company’s
tenements along the northern flank of
the basin (PELs 90K, 100 & 110).

kilometres

PEL 93 (30%)

Cooper Energy’s share of oil
production from its Cooper Basin
tenements during the year totalled
0.40 MMbbl, 26% below that
achieved in the previous year.

Four oil exploration wells were drilled
in the Cooper Basin during the year,
three of which did not encounter
significant hydrocarbons and were
plugged and abandoned. Akela-1
(PEL 110, Cooper Energy 20%)
encountered oil shows in the
Birkhead Formation, however poor
hole conditions prevented testing or
sampling of reservoir fluids. The well
was cased and suspended to allow
further evaluation and potential testing.

Four oil appraisal/development
wells were drilled in the Perlubie,
Elliston and Callawonga oil fields
(PEL 92, Cooper Energy 25%).
Perlubie-3 and Elliston-2 were both
plugged and abandoned after
encountering sub-commercial oil
columns while Callawonga-10 and
Callawonga-11 were both successful
and, subsequent to the end of the
year, were completed for oil production
from the Namur Sandstone.

* The PEL 92 Joint Venture (Cooper Energy
25%) holds twenty Petroleum Production
Licences and twenty Petroleum Retention
Licenses (PRLs 85-104), all of which were
originally licenced as PEL 92.

140°20'

Cooper Energy
tenement

Other tenements

Oil field

Gas field

Oil pipeline

Gas pipeline

3D seismic survey

Plugged and
abandoned well

140°40'

PEL 110 (20%)

-27°00'

Dundinna
3D seismic
survey

Akela-1

Jenners-1

'
0
0
°
7
2
-

Kiwi

Keleary

Telopea

PEL 100 (19.17%)

Tarragon

Cleansweep

kilometres

PEL 90K (25%)

Cooper_45AR

139°30'
139°30'

139°40'

139°50'

Worrior-10

Worrior

PPL 207

Worrior-8

1 kilometre

Inset

-28°20'

Worrior

Worrior-10

PEL 93 (30%)

Worrior-8

PEL 93 (30%)

C O

See inset

O P E R B A SIN

-28°30'

Cooper Energy
tenement

Other tenements

Oil field

Gas field

Oil pipeline

Gas pipeline

Oil well

Oil show

kilometres

-28°40'

Cooper_44AR

Results from the Callawonga wells
contributed to an increase in the EUR
(estimated ultimate recovery) for that
field which has been incorporated
in Cooper Energy’s year-end reserve
statement.

Extended production testing of the
Patchawarra Formation in Worrior-10
and Worrior-8 was undertaken
during the year. The results indicated
a smaller oil pool than previously
interpreted and caused a reduction
in Cooper Energy’s assessment of
reserves in that formation. The future
appraisal and development strategy
of the Patchawarra Formation at
Worrior will be re-assessed in FY16.

In Cooper Energy’s western flank
acreage of the Cooper Basin, the
PEL 92 Joint Venture merged and
reprocessed the Neritus, Modiolus
and Calpurnus 3D seismic surveys
(590 km2). Seismic inversion of
164 km2 of the Caseolus 3D seismic
survey data was also undertaken in
PEL 92. In PPL 207 (Cooper Energy
30%), the Worrior field 3D (52 km2)
seismic data were reprocessed.

The northern Cooper Basin permits
PEL 90K (Cooper Energy 25%),
PEL 100 (Cooper Energy 19.165%)
and PEL 110 (Cooper Energy 20%)
were the focus of the Dundinna 3D
seismic survey conducted in FY14.
Processing of the survey data was
completed during FY15 and a seismic
inversion project commenced over
595 km2 of this survey.

Review of Operations

Gippsland Basin

Cooper Energy’s interests in the
Gippsland Basins comprise:

- a 50% interest in VIC/RL3 which

M e l b o u r n e

holds the Sole gas field;

VICTORIA

Orbost

EAST E R N G

Sydney

E LIN E

S P I P

Orbost Gas Plant (50%)

- a 65% interest in, and Operatorship
of, 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; and

- a 50% interest in the Orbost Gas

Plant, onshore Victoria.

Sole Gas Project and Orbost
Gas Plant

The company’s acquisition of a
50% interest in the Sole gas field
and Orbost Gas Plant was completed
on 22 May 2015. The acquisition
was achieved through an initial
cash payment of $2.5 million and
a commitment to fund 100%
of the initial $50 million of future
project costs.

The Sole field is an undeveloped
offshore gas resource located
approximately 65km from the Orbost
Gas Plant, which is connected to the
Victorian and New South Wales gas
markets via the Eastern Gas Pipeline.
Cooper Energy assesses the Sole
field to contain a Contingent Resource
(2C) of 211 PJ of sales gas (100%
Joint Venture).

Front End Engineering and Design
(FEED) for the development of
the Sole resource commenced in
May and is expected to lead to
a Final Investment Decision (FID)
in the September quarter 2016.
Development of the field is expected
to comprise a single vertical subsea
well and pipeline to the Orbost Gas
Plant for gas supply of approximately
25 PJ per annum over 8 years
commencing from early 2019.

Lakes Entrance

Patricia-Baleen

Longtom

Tuna

Kipper

VIC/RL3 (50%)

Sole

Sole-2

Sole-1

Snapper

Marlin

Flounder

Chimaera

Manta
Basker

Gummy

VIC/L27 (65%)

VIC/L28 (65%)

Fortescue

VIC/L26 (65%)

Kingfish

kilometres

Gippsland_28AR15

Cooper Energy tenement

Gas field

Oil field

Gas well

Gas pipeline

Oil pipeline

Plan area

TAS

Potential gas pipeline

Inset

VIC/RL3 (50%)

785

5
800

795

Sole

Sole-2

Sole-1

Sole-2

805

810

815

755
6
7

805

Gas well

Depth contour
metres subsea
(5m interval)

Fault window

GWC

5
7 6 0

765

7 7 5

7 8 0

7 8 5

7 9 0
795

800

5
0
8

805

8 0 0

Sole-1

kilometres

Sole Field, Latrobe Group, Top Kingfish structure map

Gippsland 29_AR15

VIC/L27 (65%)

VIC/L26 (65%)

3230

3250

3260
3270

3280

Gas water contact

Oil and gas well

Gas well

Depth contour metres subsea
(10m interval)

Fault window

8
2
L
/
C
I
V

Chimaera 1

3290

3300

3310
3320

3280

Manta-1

kilometres

Manta-2, 2A
3 3 2 0
3330
3340 3 3 5 0

3380
0
0
3 4 1 0

B
Basker 2, 3, 4, 5, and 6

VIC/L27

VIC/L26

VIC/L28

Inset

Gippsland 30_AR15

4 kilometres

Basker-1

Manta Field, Golden Beach structure map

Gummy-1

Note: Manta 2A did not penetrate
Golden Beach sequence

BMG Project – Manta Gas Field

A seismic inversion project was
undertaken during the year and
the results integrated into the
understanding of the reservoir and
hydrocarbon distribution of the
Manta field. This work, together with
dynamic simulation modelling, was
used to re-assess the Contingent
Gas Resource in the Manta field as
106 PJ and 3.2 million barrels of
oil and condensate (100% Joint
Venture) and a further 11 PJ risked
best estimate Prospective Resources.
This total resource of 21.4 MMboe
represents a 22% increase on the
previous assessment, which was
reported in August 2014. In relation
to the Prospective Resources, the
estimated quantities of petroleum that
may potentially be recovered by the
application of a 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.

Utilising the revised resource
assessment, the company prepared
a Business Case for potential
development of the Manta field which
concluded that development of the
Manta gas resource is technically
and economically feasible. The most
economic development option is
considered likely to comprise two
subsea wells connected by pipeline
to the Orbost Gas Plant. Such a
development could result in first gas
production within two years of FID
with the potential to produce 23 PJ
of gas per year.

The Business Case outlined an
indicative schedule with development
feasibility being confirmed by Manta-3
appraisal well towards the end of
2017, entry into FEED early in 2018,
followed by FID early in 2019. Based
on this schedule, first gas could be
achieved mid-2021.

The BMG Joint Venture will assess the
Manta Business Case early in FY16
and determine the next step in the
appraisal and/or development program
of the Manta and Basker fields.

Review of Operations

Kingston SE

SOUTH AUSTRALIA

PEL 186 (33.33%)

Naracoorte

PEL 495 (30%)

Robe

ROBE TROUGH

ST CLAIR TROUGH

Beachport

Bungaloo-1

Jolly-1

Penola

Katnook
Nangwarry

PEL 494 (30%)

Millicent

Withdrawn

Cooper Energy tenement

Relinquishment application

VICTORIA

Gas field

Gas pipeline

Depositional trough

Plugged and abandoned well

Well with gas show

Hamilton
Hamilton

Mount Gambier

PRL 32 (30%)

PEP 171 (25%)

ARDONAC

HIE T

PEP 150 (20%)

PEP 168 (50%)

PEP 151 (75%)

Plan area

TAS

Portland

Warrnambool

kilometres

Cobden

Otway 31AR15

Otway Basin
Cooper Energy holds interests in
8* exploration licences in the onshore
Otway Basin covering a total area of
10,145 sq km. 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 and
Bungaloo-1, which were 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 495 was undertaken.

Applications to consolidate PELs 494
and 495 into a single licence and to
renew for an additional five-year term
were submitted to the South Australian
regulatory authority. In accordance with
regulatory requirements, the renewal
application incorporates relinquishment
of 50% of the combined licence area.

Applications to suspend and extend
PEPs 150, 151, 168 and 171 for a
further 12 months due to the ongoing
moratorium on gas production
operations were submitted to the
Victorian regulatory authority.

* Cooper Energy withdrew from the PEP 151
Joint Venture during the year and ministerial
approval of the transfer of the company’s
interest in the tenement to the continuing
Joint Venture party is expected early in FY16.

Indonesia
Cooper Energy holds interests and
operates three tenements in the
onshore South Sumatra Basin.

Tangai-Sukananti KSO
(55% interest & Operator)

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

Two operations were undertaken to
increase production from the KSO:
a workover of Tangai-3 and drilling of
the Bunian-3 development well.

The workover of Tangai-3 was
undertaken in July 2014 and resulted
in the well re-commencing production
in that month. Tangai-3 produced
at an average rate of 21 bopd during
FY15.

Bunian-3 spudded in December
2015. Operational issues necessitated
two sidetracks, with the second
sidetrack (Bunian-3 ST2) intersecting
the TRM3 reservoir sand 18.5 metres
higher than at Bunian-1 and recording
a stabilised flow rate equivalent to
1,742 bopd and 1.25 MMcfd of
gas through a 12/64 inch choke in
production testing of the TRM3.

A new oil pool discovery was also
made by Bunian-3 ST2 in the deeper
K1 Sandstone.

103° 00' E

INDONESIA

Meruap

Piano

Gambang

Suban

Tampi

3° 00' S

Merangin III PSC (100%)

kilometres

Cooper Energy permit

Oil field

Gas field

Pipeline

E
104° 00' E

Kaliberau

SOUTH CHINA SEA

MALAYSIA

I N D O N E S I A

Sumarta

South Sumatra Basin

JAVA SEA

INDIAN OCEAN

Palembang

Sungai
Gerong

Plaju Refinery

Sumbagsel PSC (100%)

Tangai-Sukananti KSO (55%)

4° 00' S
4° 00' S

Indonesia_116AR15

The K1 Sand flowed on test at a
rate equivalent to 1,590 bopd and
1.8 MMcfd of gas through a 1/8 inch
choke.

higher than the average rate of
approximately 320 bopd being
achieved prior to Bunian-3
commencing production.

Studies will be undertaken to optimise
further development of Bunian,
which is likely to lead to drilling and
installation of increased export
capacity in the 2016 calendar year.

Sumbagsel PSC
(100% interest & Operator)

The Sumbagsel PSC lies on the
eastern flank of the South Sumatra
Basin and contains a wide prospect
inventory of shallow oil and deeper
gas prospects and leads.

Interpretation of 265 km of 2D
seismic was undertaken. Acquisition
of 3D seismic is planned for the
2016 calendar year.

An application to relinquish 15%
of the original contract area was
submitted to SKKMigas, in
accordance with the conditions
of the PSC.

Merangin III PSC
(100% interest & Operator)

The Merangin III PSC lies in the
central portion of the South Sumatra
Basin and contains a wide prospect
inventory of shallow oil and deeper
gas prospects and leads.

Interpretation of over 3,000km of
2D seismic data from the PSC was
completed during the year, with the
objective of maturing targets for
2D seismic acquisition in the 2016
calendar year.

The well’s results were the key factors
in an increase in 2P oil reserves in
the Bunian field at 30 June 2015 to
1.53 MMbbl (Cooper Energy share),
which is an increase of 1.20 MMbbl
from the 2P Reserves of 0.33 MMbbl
at 30 June 2014.

Bunian-3ST2 was completed as an
oil producer from the TRM3 and
K1 Sands and was brought online in
May 2015.

In July-August 2015, although
constrained by trucking and handling
capacity, total production from the
KSO averaged 760 bopd, significantly

104°55'

Bunian-2

INDONESIA

TMB-06

Tanjung Miring
Barat

Bunian-1

Tangai-Sukananti KSO

Bunian-3ST1

Bunian

Bunian-3ST2

Bunian-4

Sukananti-1

Cooper Energy permit

Oil field

Oil well

Abandoned oil well

Dry well

Indonesia_117_AR15

Kupang-1

Tangai-3

Tangai-1

Tangai

Tangai-4

Tangai-2

-3°35'

kilometres

Review of Operations

10°E

37°N

Tunis

36°N

11°E

12°E
Hammamet Permit (35%)

Bargou Permit (30%)

Lambouka

Dougga

Pantelleria Island
(Italy)

Zibibbo

Aster

13°E
13°E

MEDITERRANEAN SEA

Map area

TUNISIA

Neopolis

Tazerka

Yasmin

Birsa

Fushia

Zelfa

Cosmos

Oudna

Lotus

Sbeitla

El Mediouni

Nabeul Permit (85%)

Halk El Menzel

Cooper Energy tenement

Hammamet West-3

Maamoura
Tafernine

Baraka
Baraka SE

Baraka South

Sousse

Monastir

TUNISIA

Tunisia_35AR15

kilometres

Oil field

Gas field

Gas pipeline

Oil well

Acquisition of this seismic program
and the abandonment of Hammamet
West-3 may be undertaken during
FY16.

Nabeul Permit
(Cooper 85% & Operator)

No activity was undertaken in the
Nabeul permit.

During the year the company
elected to not extend the tenure of
its interest in the Nabeul permit.
The terms to finalise the exit from
the permit are to be agreed with the
Tunisian Government.

Hammamet Permit
(Cooper 35%)

There was no significant activity during
the year in the Hammamet permit.

Tunisia
Efforts to divest the company’s
entire Tunisian portfolio continued
but were hindered by the downturn
in oil prices and industry sentiment.
Accordingly the focus during the year
was to negotiate as far as possible
the deferment and/or reduction of
work obligations, particularly in the
Bargou and Nabeul permits.

Bargou Permit
(30% interest & Operator)

Activity in the Bargou permit during
the year consisted of reprocessing
of the Hammamet West 3D seismic
survey. Plans for further drilling on
the Hammamet West oil discovery
were postponed indefinitely.

Subsequent to year-end an
application to remove this well
commitment and to amend the
remaining work obligations
in the Bargou permit to 600km of
3D seismic was approved by the
Tunisian government authority.

Health Safety Environment and Community
A core Cooper Energy value is Care: prioritising safety;
health; the environment; and community.

• 957,000 hours worked with one

Lost Time Injury

• Zero Lost Time Injuries during
onshore drilling activities in
South Sumatra

• Offshore subsea inspection

campaign successfully carried
out at Basker-Manta with excellent
safety performance and no
recordable incidents

• Community participation via ‘Making

a Difference’ program

Health and Safety

Cooper Energy staff and contractors
worked a total of 957,000 hours
during the year with just one Lost Time
Injury (LTI), resulting in a Lost Time
Injury Frequency Rate (LTIFR) of 1.04
incidents per million hours worked,
against a target rate of below 0.80.
The LTI occurred during a downhole
fluid sampling operation in South
Sumatra and was attributed to workshop
misassembly of the equipment that
caused unexpected release of trapped
pressure during deployment at
the wellsite.

Cooper Energy also monitors and
measures Total Recordable Cases
(TRCs), a broader standard safety
performance metric. TRCs include LTIs,
alternate duties injuries and incidents
requiring any medical treatment
greater than simple first aid. In total,
four incidents were recorded during the
year resulting in a Total Recordable
Case Frequency Rate (TRCFR) of 4.2
incidents per million hours worked.

Lessons from all incidents and near
misses have been incorporated into
improved operational procedures.

A safety highlight was the 11-day subsea
inspection campaign carried out on
the Basker and Manta fields, offshore
Victoria, using a Remote Operated
Vehicle (ROV) deployed from the Bass
Trek vessel. Despite the inherent risks
of working in the harsh Bass Strait
environment, a thorough pre-campaign
risk assessment, together with detailed
planning and preparation followed
by diligent execution resulted in the
operation being completed ahead of
schedule and under budget with no
recordable safety incidents.

The Care value encompasses support
of staff and Cooper Energy formally
encourages staff health through the
incorporation of health and well-being
targets in individual objectives.

Environment

No recordable environmental incidents
occurred in Cooper Energy operations
during the year.

Cooper Energy takes a proactive
stance with respect to its environmental
responsibilities. Although the company
is below the reporting threshold required
by the National Greenhouse and Energy
Reporting Act, it has commenced
recording and reporting its Australian
emissions and energy use in order
to establish a baseline in preparation for
the commencement of gas production
from its offshore gas projects in Victoria.

Community

Cooper Energy chooses to participate
in, and contribute to, the communities in
which it operates. This is carried out via
the organisation’s ‘Making a Difference’
program through which the company
provides both financial and ‘hands-on’
assistance from the time and efforts of
its staff and contractors to selected not-
for-profit organisations addressing social,
environmental and community needs.

Organisations assisted directly by the
program during the year included;
Fred’s Van (an initiative of St Vincent
de Paul), Hutt St Centre for the
Homeless, Foodbank, Juvenile Diabetes
Research Fund, The Hospital Research
Foundation, KickStart for Kids and the
Nature Foundation SA Revegetation
program. More than 80% of Australian
office staff has taken part in at least
one event as part of the program.

Our Commitment

Cooper Energy is committed to pursuing
industry leading HSEC performance,
via a range of initiatives. For a smaller
company working a limited number of
hours it is important an appropriate
balance is maintained whilst doing all
reasonably possible to ensure leading
HSEC performance. Low accident
statistics are ultimately a key objective of
the safety outcomes achieved. However,
these historical statistics have limited
utility as a predictive tool for identifying
the most effective concentration of
future efforts. It is similar for our efforts
in health, environment and community.

Accordingly, the company is broadening
its perspective to examine a selection
of relevant incidents and High Potential
Near Misses from the wider industry
and working to implement lessons
from this analysis across its operations.
This work is being integrated into a
framework based around the principles
of continuous improvement and
mindfulness.

Portfolio
Exploration and Production Tenements

Region: Australia

Cooper Basin

State

Tenement

Interest

Location Area (km2)

Operator

Activities

South Australia

PPL 204 (Sellicks)

25%

Onshore

2.0

Beach Energy

Production

PPL 205
(Christies /Silver Sands)

PPL 207 (Worrior)

PPL 220 (Callawonga)

PPL 224 (Parsons)

PPL 245 (Butlers)

PPL 246 (Germein)

PPL 247 (Perlubie)

PPL 248 (Rincon)

PPL 249 (Elliston)

PPL 250 (Windmill)

PEL 90 (Kiwi sub-block)

PRL 85-104

PEL 93

PEL 100

PEL 110

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

20%

Onshore

727.5

Senex Energy

Exploration

Otway Basin

State

Tenement

Interest

Location Area (km2)

Operator

Activities

33%

30%

20%

75%

50%

25%

Onshore

709.1

Cooper Energy

Exploration

Onshore

2,488.8

Beach Energy

Exploration

Onshore

36.9

Beach Energy

Exploration

Onshore

3,212.0

Beach Energy

Exploration

Onshore

859.0

Bridgeport Energy

Exploration

Onshore

795.0

Beach Energy

Exploration

Onshore

1,974.0

Beach Energy

Exploration

Interest

Location Area (km2)

Operator

Activities

65%

50%

Offshore

67.0

Cooper Energy

Production

Cooper Energy

Production

Cooper Energy

Production

Offshore

201.0

Santos

Retention

South Australia

PEL 186

PEL 494

PRL 32

PEP 150

PEP 1511

PEP 168

PEP 171

Tenement

VIC/L26

VIC/L27

VIC/L28

VIC/RL3

Victoria

Gippsland Basin

State

Victoria

Orbost Gas Plant, Gippsland Basin, Victoria

Region: Indonesia

South Sumatra Basin

Tenement

Interest

Location

Area (km2)

Operator

Tangai-Sukananti KSO

Sumbagsel PSC

Merangin III PSC

55%

100%

Onshore

18.3

1,304

1,488

Cooper Energy

Region: Tunisia

Gulf of Hammamet

Tenement

Bargou

Hammamet

Nabeul

Interest

Location

Area (km2)

Operator

30%

35%

85%

Offshore

4,616

4,676

Cooper Energy

Storm Ventures International

Exploration

3,352

Cooper Energy

Exploration

1. During the year Cooper Energy withdrew from the PEP 151 Joint Venture. Ministerial approval of the transfer of the company’s

interest in the tenement to the continuing Joint Venture party had not occurred by 30 June 2015 but is expected in the first half of
the 2016 financial year.

Activities

Production

Exploration

Activities

Exploration

Board of Directors

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.

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

Chairman
Mr John C. Conde AO
B.Sc. B.E(Hons), MBA

Independent Non-Executive
Director

Appointed 25 February 2013

Independent Non-
Executive Director
Mr Jeffrey W. Schneider
B.Com

Appointed 12 October 2011

Experience and expertise
Mr Conde has extensive experience in
business and commerce and in chairing
high profile business, arts and sporting
organisations.

Previous positions include, a 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 currently Chairman of
Bupa Australia (since 2008) and
The McGrath Foundation (since 2013
and Director since 2012).

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).

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

Appointed 28 August 2013

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 Djerriwarrh Investments Ltd ASX:
DJW (since 2010), Equity Trustees Ltd ASX:
EQT (since 2007), Barristers Chambers Ltd
(since 2015), the Foreign Investment Review
Board (since 2015), Guild Group, Defence
Health and Port of Melbourne Corporation.
Ms Williams is also a Council member of
the Cancer Council of Victoria. Ms Williams
is a former director of Victorian Funds
Management Corporation (2008 – 2015).

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

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

Appointed 12 October 2011

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

Appointed 26 June 2012

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 including
a number of material acquisitions.

Mr Maxwell has served on a number of
industry association boards, government
advisory groups and public company
boards. He was a member of the Australia
Federal Government Energy White Paper
Reference Group in 2011.

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.

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 reviewing
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.

Executive Management team

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

Exploration success rate

12 months
to 30 June

MMbbl

number

percent

Cumulative exploration success rate percent

2008

2009

2010

2011

2012

2013

2014

2015

0.38

1.44

17%

21%

0.49

1.91

60%

30%

0.47

2.00

0.41

2.47

27%

23%

0.52

1.88

50%

27%

0.49

2.16

0.59

2.01

25%

26%

24%

0.48

3.08

22%

Reserve Replacement Ratio

206%

198%

119%

215%

(14)%

157%

75%

323%

Financial

Oil sales revenue

Other revenue

EBITDA

Profit before tax

Profit after tax

Cash & term deposits

Investments

Working capital

Accumulated profit

Cumulative franking credits

$ million

45.0

3.7

15.8

6.4

64.6

73.6

26.0

9.3

41.6

40.0

39.1

5.1

(6.0)

(5.5)

(10.3)

4.3

8.0

7.2

1.2

92.5

72.4

95.4

24.4

25.7

79.5

14.1

31.4

59.6

53.4

4.7

9.1

21.0

8.4

61.5

13.2

53.4

22.5

37.0

2.3

22.3

18.3

1.3

47.9

20.2

51.7

23.8

39.0

72.3

2.8

36.9

31.2

22.0

49.1

26.0

41.2

45.7

39.1

1.9

(58.4)

(18.8)

(63.5)

39.4

1.9

43.0

(17.7)

38.7

43.7

4.2

5.2

5.0

(2.8)

93.4

96.5

23.2

17.7

Shareholders equity

$ million

115.5

123.3

125.1

114.9

136.9

137.2

167.8

103.9

Earnings per share

cents

2.9

(1.0)

0.4

(3.5)

2.8

0.4

6.4

(19.2)

Return on shareholders funds

percent

5.5% (2.3)%

1.0% (8.6)%

6.7%

0.9%

14.4% (61.1)%

Total shareholder return

percent

(41.1)% (3.2)% (17.8)%

(2.7)%

25.0% (16.7)%

34.7% (51.5)%

Average oil price

A$/bbl

118.46

86.76

87.02

95.42

114.63

112.31

124.08

85.48

Capital as at 30 June

Share price

Issued shares

$ per share

0.465

0.45

0.37

0.36

0.45

0.375

0.505

million

252.3

291.9

292.6

327.3

329.1

329.2

Market capitalisation

$ million

117.3

131.4

108.3

105.3

147.3

123.4

166.3

Shareholders

number

7,345

7,596

6,537

5,573

5,485

5,284

5,122

0.245

331.9

81.4

5,103

Cooper Energy Limited
and its controlled entities
Financial Report

For the year ended 30 June 2015
ABN 93 096 170 295

Operating and Financial Review

Directors’ Statutory 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

6. Earnings Per Share

7. Cash and Cash Equivalents and Term Deposits

Trade and Other Receivables (Current)

9. Prepayments (Current)

10. Exploration Assets Held for Sale and Discontinued Operations

11. Available for Sale Investment (Non-Current)

12.

Investments in Associate (Non-Current)

13. Oil Properties (Non-Current)

14.

Impairment

15. Other Property, Plant & Equipment (Non-Current)

16. Exploration and Evaluation (Non-Current)

17. Trade and Other Payables (Current)

18. Provisions

19. Financial Liabilities (Non-Current)

20. Contributed Equity and Reserves

21. Financial Risk Management Objectives and Policies

22. Commitments and Contingencies

23.

Interests in Joint Arrangements

24. Related Parties

25. Share Based Payment Plans

26. Auditors’ Remuneration

27. Parent Entity Information

28. Events After the Reporting Period

Directors’ Declaration

Independent Audit Report

Auditors’ Independence Declaration

Securities Exchange And Shareholder Information

Corporate Directory Inside back cover

100

101

102

104

105

Operating and Financial Review
For the year ended 30 June 2015

Cooper Energy completed the financial year with the company’s highest level of reserves and resources on record and significant
progress on executing its value enhancing gas strategy. However, the substantial decline in the world oil price during the period has
had a significant effect on Cooper Energy’s reported financial results in two principal areas – first, reduced revenues from operations
have resulted in a loss and, secondly, the Board has resolved to make impairment (non-operating) adjustments to the Tunisian
portfolio and other assets. These non-operating items have affected adversely the reported loss after tax by $62.2 million. Further
details of the financial performance and the impairment adjustments are presented later in this Report.

Operations

Overview

Cooper Energy is a petroleum exploration and production company which seeks to create shareholder value through cash generating
hydrocarbon production and the creation of a gas supply business which is focussed particularly on eastern Australia.

Revenue is generated from the discovery, development and sale of oil from licences held in the Cooper Basin, Australia and the South
Sumatra Basin, Indonesia. The company held proved and probable reserves of 3.1 million barrels of oil in these regions as at 30 June 2015.

The emerging gas business includes Contingent Resources (2C) of 196.5PJ1 in the Gippsland Basin, offshore Victoria, Australia and a
50% interest in the Orbost Gas Plant, onshore Gippsland Basin. Cooper Energy is working towards commercialisation and development of
these resources, which are scheduled to commence revenue generation from as early as January 2019. Gas exploration acreage is also
held in the onshore Otway Basin.

A portfolio of offshore Tunisian acreage is currently subject to a divestment process, the status of which is discussed under the heading
“Business Strategies and Prospects” later in this report.

Production

Cooper Energy produced a total of 0.48 million barrels of oil in 2015, 84% of which was sourced from the Cooper Basin, with the balance
from Indonesia. The production result compares to 0.59 million barrels in the preceding year, with the movement incorporating natural decline
of Cooper Basin fields and increased, and record, output from the Indonesian operations.

Cooper Basin production for the year was 0.40 million barrels, down from 0.54 million barrels in the prior year.

Indonesian production benefited from a successful workover and development drilling campaign conducted in the Sukananti KSO, most
particularly the Bunian-3 well completed in May 2015. The company’s share of production from Sukananti for the 12 months to 30 June
2015 was 0.075 million barrels compared with 0.055 million barrels in the previous year. The commencement of production in May from
Bunian-3 took production from the Sukananti KSO to the limit permitted by existing storage and transportation.

Project and portfolio development

In 2012 the company identified an opportunity for value creation in the gas supply opportunities it foresaw as emerging in eastern Australia as
existing supply contracts ran down and demand escalated with the commencement of Liquefied Natural Gas (LNG) production in Gladstone.

The company continues to implement a strategy to realise this opportunity, through creating a market focussed, portfolio-style gas supply
business. Core to this strategy is the accumulation of gas resources with the technical and commercial characteristics to be among the most
cost competitive and available in the market and a portfolio of gas supply contracts.

1 BMG contingent resource initially disclosed to the market on 18 August 2014, Sole contingent resources disclosed on 25 May 2015 and
an update to Manta resources announced on 16 July 2015. Cooper Energy is not aware of any new information or data that materially
affects the information provided in those releases and all material assumptions and technical parameters underpinning the assessment in
the announcements continue to apply.

Operating and Financial Review
For the year ended 30 June 2015

The results achieved in 2015 have seen the company establish the gas resource, infrastructure interests and, subsequent to year-end, the
first commercial agreements for the gas business envisaged by the strategy. The key developments in the strategy that led to this position are:

- the acquisition of a 50% interest in the Sole gas field (Gippsland Basin- VIC/RL3) and a 50% interest in the Orbost Gas Plant;
- recognition of Contingent Resources (2C)of 105.5 PJ2 of gas in the Sole field (Cooper Energy share);

- the Sole Gas Project entering into Front End Engineering and Design (FEED) for a gas development to supply eastern Australia via the

Orbost Gas Plant from January 2019;

- an upgrade to resources of the Manta gas field in VIC/L26 and VIC/L27. The Manta field is now assessed to hold Contingent
Resources (2C) of 106.0PJ of gas and 3.2 million barrels of oil and condensate (total joint venture volume, Cooper Energy
interest is 65%);

- completion of the Cooper Energy Business Case analysis for the Basker-Manta-Gummy gas and liquids resource in VIC/L26, VIC/

L27 and VIC/L28. The Business Case identified an opportunity for development of a gas project at the Manta gas field to supply gas to
eastern Australia, via the Orbost Gas Plant, from mid 2021; and

- negotiation with gas buyers, which resulted in the announcement of the first Heads of Agreement for supply of gas from Sole.

Discussion of the ongoing execution of the gas strategy is provided under the heading Business Strategies and Prospects below.

In Indonesia the company is pursuing a strategy which adds value through adding low risk production and reserve increments with limited
recourse to capital. As noted under the headings Exploration and development and Reserves and resources this strategy has been successful,
to the point where a new range of field appraisal and development opportunities have emerged, with the capacity to add significantly to
production rates in the coming years. The company is presently assessing the potential and shareholder value offered by these opportunities
in the context of its capital management and growth plans.

Exploration and development

Cooper Energy has interests in petroleum exploration tenements in the Cooper, Otway and Gippsland Basins in Australia, the South Sumatra
Basin in Indonesia and the Pelagian Basin offshore Tunisia. As noted, above the Tunisian acreage is the subject of a divestment process.

Exploration and development activity during the period included the drilling of 9 wells. In the Cooper Basin, 4 exploration, 2 appraisal wells and
2 development wells were drilled. The Callawonga-10 development well and Callawonga-11 appraisal wells were successful. In Indonesia, the
Bunian-3 development well was successful, leading to increased reserves and production from the field and identifying further potential to be
addressed by subsequent drilling.

Reserves and resources

Reserves and Resources were increased substantially during the year and at 30 June 2015 were the highest yet recorded by Cooper Energy.
Proved and probable reserves of 3.1million barrels of oil were 53% higher than the corresponding figure of 2.0 million barrels at the beginning
of the year. The increase is attributable to Indonesia, where the successful Bunian-3 well resulted in a major upgrade to reserves in the
Sukananti KSO, additions arising from drilling at the Callawonga field and better than forecast performance from some of the existing Cooper
Basin production wells. Proved and probable reserves additions in the Cooper Basin PEL 92 fields were sufficient to replace 120% of the
permit’s yearly production.

Contingent Resources (2C)of 58.4 million boe were 66% higher than at the start of the year, with nearly all of the increment being
attributable to the Gippsland Basin, where an initial resource booking was made for the Sole gas field acquired on 25 May and the
assessment for the Manta field upgraded. Gippsland Basin resources account for 38.4 million boe of 2C Contingent Resources, with the
balance being accounted for by Tunisia (17.0 million boe and unchanged), Indonesia (2.6 million boe, previously zero) and Cooper Basin
(0.4 million boe).

2 As disclosed to the ASX on 25 May 2015. Cooper Energy is not aware of any new information or data that materially affects the information

provided in those releases and all material assumptions and technical parameters underpinning the assessment in the announcements
continue to apply.

Operating and Financial Review
For the year ended 30 June 2015

Financial Performance

Production volume

Sales volume

Sales revenue

Average oil price

Gross profit

Gross profit / Sales revenue

Operating cash flow

Reported NPAT / (loss)

Underlying NPAT / (loss)

Underlying EBITDA*

MMbbl

$million

$/bbl

$million

FY15

0.48

0.46

39.1

85.48

14.1

36.0

2.0

-63.5

-1.3

8.2

FY14

Change

0.59

0.58

72.3

-0.11

-0.12

-33.2

124.10

-38.62

46.2

64.0

50.3

22.0

25.3

40.2

-32.1

-28.0

-48.3

-85.5

-26.6

-32.0

-18%

-21%

-46%

-31%

-69%

-44%

-96%

-389%

-105%

-80%

* Earnings before interest, tax, depreciation and amortisation

Calculation of underlying NPAT / loss by adjusting for items unrelated to the ongoing operating performance is considered to provide
meaningful comparison of results between periods. Underlying NPAT / loss and Underlying EBITDA are not defined measures under
International Financial Reporting Standards and are not audited. Reconciliations of NPAT / loss and Underlying NPAT / loss and Underlying
EBITDA are included at the end of this review.

Cooper Energy recorded a statutory loss after tax of $63.5 million for the 30 June 2015 financial year which compares with the profit after
tax of $22.0 million recorded in the 2014 financial year. The 2015 statutory loss included a number of non-operating items which adversely
affected profit after tax by $62.2 million. These items which principally comprise impairment in respect of the Tunisian discontinued
operations are detailed in the reconciliation for NPAT to Underlying NPAT at the end of this review.

Underlying loss exclusive of these items was $1.3 million, compared with the previous year underlying NPAT of $25.3 million, with the
movement being attributable to:

• significantly lower oil prices. The average oil price of A$85.48/bbl was 31% lower than the 2014 average of $124.10 /bbl.

This difference was responsible for a $22.5 million reduction in sales revenue;

• lower sales volumes, due to lower production. Sales volumes were 21% lower than in 2014, resulting in a $10.7 million reduction in

sales revenue;

• amortisation of costs in areas under production rose $1.5 million due to revised estimated development expenditure on undeveloped

reserves; and

• lower other revenue, $1.0 million, with lower joint venture fees.

These factors were offset in part by:

• lower tax expense by $12.0 million, mainly due to the lower underlying profit before tax; and

• lower royalties by $3.2 million due to lower oil prices and production.

Financial Position

Total assets

Total liabilities

Total equity

Assets

$million

FY15

174.0

70.1

103.9

FY14

248.3

80.5

167.8

Change

-74.3

-10.4

-63.9

-30%

-13%

-38%

Total assets decreased by $74.3 million from $248.3 million to $174.0 million.

Cooper Energy has a strong balance sheet. As at 30 June the company held cash and deposit balances of $39.4 million, investments of
$1.9 million and no debt.

Total financial assets declined by $33.9 million over the period after funding exploration and development of $27.4 million. As illustrated
below, operating net cash was $2.0 million after net working capital movements of $10.7 million including income tax of $5.9 million
relating to 2014.

Operating and Financial Review
For the year ended 30 June 2015

Financial Position continued

$ million

Total cash &
investments
$75.1

26.0

22.5

-11.3

Total cash &
investments $41.3

Investments
(at fair value)

49.1

Cash &
deposits

-10.7

1.5

51.1

-27.4

15.4

0.3

Investments
(at fair value)

1.9

39.4

Operating
+$2.0m

Investing,
Financing & FX
-$11.7m

Cash &
deposits

June 14 Operations General Net Working Interest Operating E & D
Capital
Movement

Admin

Other
Investment

Financing June 15

& FX

Exploration and evaluation assets (including those held for sale at 30 June 2014) decreased $36.1 million from $141.5 million to
$105.4 million primarily as a result of the impairment of $47.5 million on the Tunisian discontinued operations partially offset by exploration
expenditure during the period, including the acquisition of Sole and the Orbost Gas Plant.

Oil properties decreased by $6.4 million from $18.3 million to $11.9 million mainly due to an impairment of $7.5 million for PEL 93
(refer to note 14) and amortisation, partially offset by capital expenditure during the period.

Total Liabilities

Total liabilities decreased by $10.4 million from $80.5 million to $70.1 million.

Trade and other payables decreased $3.4 million from $12.3 million to $8.9 million mainly due to the timing of payments to suppliers with
FY14 payables being high relative to a three year average.

Income tax payable decreased by $5.0 million to nil due to payment of tax made in the period. Subsequent to year end the FY14 income tax
return was amended for a research and development claim of $0.8 million which is shown as income tax receivable as at 30 June 2015.
No income tax is payable at 30 June 2015.

Net deferred tax liabilities decreased by $3.4 million from $14.4 million to $11.0 million mainly due to the impairment losses recognised in
respect of exploration and evaluation.

Financial liabilities decreased by $0.9 million from $4.0 million to $3.1 million due to a reset of assumptions relating to the BMG success
fee liability.

Provisions increased by $5.2 million from $41.9 million to $47.1 million mainly due to the acquisition of the Sole field and Orbost Gas Plant
with abandonment provisions of $8.1 million, partially offset by a decrease in the Basker-Manta-Gummy rehabilitation provision as a result
of a reset of assumptions.

Total Equity

Total equity has decreased by $64.0 million from $167.8 million to $103.8 million. In comparing equity for the period to the prior
corresponding period the key movements were:

• higher accumulated losses due to the total loss for the year of $63.5 million;

• lower reserves of $1.3 million mainly due to fair value adjustments on investments available for sale in addition to a sale of investments;

and

• higher contributed equity of $0.8 million due to vesting of performance rights into shares.

Operating and Financial Review
For the year ended 30 June 2015

Business Strategies and Prospects

The company’s strategy has three key elements:

- cash generating production, both from existing operations and from new sources in Australia;

- retention of a strong financial position and balance sheet; and

- development of a gas business supplying eastern Australia.

The company will apply its resources to these key elements with the objectives of generating optimal shareholder value, on those
opportunities which satisfy fundamental, commercial and technical merit criteria whilst taking due care for safety, the environment and
communities in which we operate.

The company’s oil production on the western flank of the Cooper Basin features low direct operating costs, including transport and
royalties, averaging A$35/bbl in 2015. The operating costs for the Indonesian operations are reducing as its production increases, and
averaged A$45/bbl for the full year. These existing production operations are considered to be viable at current and anticipated
Australian dollar oil prices.

Production from existing Cooper Basin and Indonesian interests will be optimised to continue to maximize cash flow and support the
company’s clear growth plans. Low risk exploration and appraisal drilling will continue in the Cooper Basin and Indonesia with the intention of
maintaining production of approximately 500,000 barrels of oil per annum. Additional production opportunities will also be considered where
they add value consistent with the company’s strategy.

The establishment of a gas business supplying eastern Australia is now well underway with both the Sole and Manta projects being advanced,
albeit at different stages of maturity. Marketing activities have confirmed there is demand for gas from Sole and Manta and that price
expectations are comfortably within that required for an economic project.

Ongoing execution of the gas strategy will now focus on:

- progression of the Sole project through FEED for a Final Investment Decision ( FID) likely in the September 2016 quarter;

- joint venture review of the Manta opportunity concurrent with planning of appraisal activity;

- negotiation of additional gas sales agreements prior to FID for the Sole project; and

- determination and implementation of the most suitable funding arrangements.

The company has previously announced its intention to divest its Tunisian portfolio in order to concentrate its resources on assets
consistent with its strategy. The divestment process is yet to generate acceptable offers. Current market conditions and sentiment mean
that exit from Tunisia through a transaction of the portfolio is not presently foreseeable. Cooper Energy is seeking to defer and limit further
capital expenditure and accordingly has advised the Tunisian Government of its intention to not extend or renew the Nabeul permit and
is continuing efforts to divest and reduce commitments in the Bargou and Hammamet permits as soon as practicable.

2016 Outlook

Cooper Energy expects production for the twelve months to 30 June of between 0.45 million to 0.55 million barrels of oil from the Cooper
Basin and Indonesia with the range of expectations reflecting the potential impact of drilling results and the timing of well connections.

Increased production from Indonesian operations is forecast to offset natural decline from current Cooper Basin wells. Indonesia is forecast
to broadly account for 35% of the year’s production. Direct operating costs, including transport and royalties, are forecast to approximate
A$38/barrel for total production.

Capital expenditure is being primarily directed to the company’s growth projects, whilst maintaining investment in production from existing
operations. Total capital expenditure of approximately $39 million is planned, with more than half of this attributable to the Gippsland gas projects.

Exploration and development activity for the year is expected to include:

• the drilling of 2 exploration wells and 2 development wells by the PEL92 Joint Venture and interpretation of 3D seismic data reprocessed

in the previous year;

• the drilling of the Bunian-4 development well and establishment of additional production capacity in the Sukananti KSO;

• data processing of seismic information acquired in the northern Cooper Basin permits PEL 90K, 100 and 110; and

• reprocessing of 3D seismic information acquired in the Otway Basin.

Contingent activity not included in the firm capital expenditure plan includes 3 development wells in the Cooper Basin (PEL 92 Joint
Venture: 2 contingent wells; and PEL93 Joint Venture 1 contingent well), and a contingent exploration well in the Otway Basin.

Progression of the Sole Gas Project through FEED to an affirmative FID stands as the most significant opportunity for value accretion in
the year. To achieve this important milestone requires completion of the necessary engineering and commercial analysis, securing the
required government approvals, finalising gas sales contracts and determining the most appropriate funding arrangements. Achievement
of these outcomes will result in the translation of the field’s gas resources to proven and probable reserves, which on 2C Contingent
Resource current estimates represents an uplift of 18 million boe.

Cooper Energy expects to secure satisfactorily priced gas contracts and FEED in the coming 12 months.

Operating and Financial Review
For the year ended 30 June 2015

Funding and Capital Management

As at 30 June 2015 the company had cash, deposits, and investments of $41.3 million. The company currently has $40 million in bank
facilities which are subject to conditions and are currently being restructured from corporate to reserve based lending. The company
considers its funding to be adequate for capital expenditure anticipated in the 2016 financial year.

The company has conducted and completed a comprehensive analysis of funding requirements and options available, especially in view
of the capital expenditure requirements anticipated for the development of the company’s gas projects in the Gippsland Basin. The analysis
confirmed a range of funding alternatives is likely to be available to provide coverage of the funding requirements anticipated for these
projects and the Company’s participation in them. The determination of the most suitable combination of these options and timing is a
matter of ongoing deliberation.

Risk Management

The company manages risks in accordance with its risk management policy with the objective of ensuring all risks facing the business are
identified, measured and then managed or kept as low as reasonably practicable. The Management Team perform risk assessments on a
regular basis and a summary is reported to the Audit and Risk Committee. The Audit and Risk Committee approves and oversees an internal
audit program undertaken by an external tier 1 accounting firm.

Key risks which may materially 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.

Appropriate policies and procedures are continually being developed and updated to help manage the risks.

Reconciliations for NPAT to Underlying NPAT and Underlying EBITDA

Reconciliation to Underlying (loss) / NPAT

Net (loss) / profit after income tax (NPAT)

Adjusted for:

Discontinued operations

Impairment of oil properties

Impairment of exploration and evaluation

Impairment of financial assets AFS

Impairment of investment in associate

Fair value movement on disposal on investments

$million

Accounting gain on acquisition of associate investment

$million

Unrealised fair value movement on derivatives

Tax impact of above changes

Underlying (loss) / NPAT

Reconciliation to Underlying EBITDA*

Underlying NPAT

Add back:

Interest revenue

Accretion expense

Tax expense / (benefit)

Depreciation

Amortisation

Underlying EBITDA*

* Earnings before interest, tax, depreciation and amortisation

$million

FY15

-63.5

FY14

22.0

Change

-85.5

389%

47.6

7.5

7.2

7.5

0.5

-3.6

-0.3

0.2

-4.4

-1.3

-1.2

0.5

1.4

0.5

8.3

8.2

0.2

0.0

3.1

0.0

47.4

23700%

7.5

7.2

4.4

0.5

-3.6

-0.3

0.2

-4.4

100%

142%

100%

-100%

100%

-100%

-105%

25.3

-26.6

25.3

-26.6

-105%

-1.4

0.0

9.0

0.5

6.8

0.2

0.5

-7.6

0.0

1.5

40.2

-32.0

-14%

100%

-84%

22%

-80%

Directors’ Statutory Report
For the year ended 30 June 2015

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 2015, 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, a 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 currently 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 including a number of material acquisitions.

Mr Maxwell has served on a number of industry association boards, government advisory groups and
public company boards. He was a member of the Australia Federal Government Energy White Paper
Reference Group in 2011.

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.

Directors’ Statutory Report
For the year ended 30 June 2015

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 reviewing 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 Djerriwarrh Investments Ltd ASX: DJW (since 2010),
Equity Trustees Ltd ASX: EQT (since 2007), Barristers Chambers Ltd (since 2015), the Foreign
Investment Review Board (since 2015), Guild Group, Defence Health and Port of Melbourne
Corporation. Ms Williams is also a Council member of the Cancer Council of Victoria. Ms Williams
is a former director of Victorian Funds Management Corporation (2008 – 2015).

Special Responsibilities

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

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 held Company Secretary and Legal Counsel roles 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 and commercial management, mostly in the construction 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.

Directors’ Statutory Report
For the year ended 30 June 2015

3. Directors’ meetings

The number of Directors’ meetings (including meetings of committees of Directors) and number of meetings attended by each of the
Directors of the parent entity 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 (Audited)

This Remuneration Report sets out information about the remuneration of the Company’s key management personnel for the financial year
ended 30 June 2015. 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 Key Management Personnel (KMP)

The following were KMP of the Group during the reporting period and, unless indicated otherwise, for 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)1

1 Appointed 4 August 2014

4.2 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 between:

• maximising sustainable shareholder returns;

• operational and strategic requirements; and

• providing attractive and appropriate remuneration packages to management and employees.

The primary objectives of the Company’s remuneration policy are to:

• attract and retain high-calibre people;

• 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 transparency and credibility for all employees and in particular for Executive remuneration.

Directors’ Statutory Report
For the year ended 30 June 2015

4. Remuneration Report (Audited) continued

4.2 Remuneration Philosophy and Objectives continued

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. This is intended to bring the overall total remuneration package to the upper quartile of the market only
when top level performance is achieved.

4.3 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 4.11).

4.4 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 KMP remuneration by reference to relevant employment market conditions and third party
remuneration benchmark reports. The Committee determines remuneration arrangements in conjunction with the annual performance

reviews of KMP.

4.5 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. Non-Executive Director remuneration was last increased in February 2013. After reviewing the Non-executive
Directors’ fees, the Board has determined that, given the current market conditions, there would be no increase in Non-Executive Directors
fees for the 2016 financial year.

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. It allows for fair and competitive remuneration of additional
well-credentialed directors as may be appointed in the future to assist the Company to achieve its strategic goals.

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 during their term.

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.

4.6 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 (being the award of performance rights under the Company’s employee performance rights plan).

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 (respectively), and each of the above remuneration components is discussed further below.

Directors’ Statutory Report
For the year ended 30 June 2015

4. Remuneration Report (Audited) continued

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

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 salary.

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

The Board reviewed the base salaries for the Managing Director and Executive Director – Production & Exploration in August 2015.
Following this review, the Board determined that given current market conditions, there would be no increase to their base salaries as a
result of this annual review.

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.

Directors’ Statutory Report
For the year ended 30 June 2015

4. Remuneration Report (Audited) continued

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

In the financial year 2015, the scorecard KPIs and their relative weightings were as follows:

STIP Key Performance Indicators

% Rationale for choosing KPI

HSEC performance

Increased production from existing assets

Growth in reserves and resources

Key gas strategy milestones

Cost management

Processes and Risk Management

Stakeholder Relationships

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.

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 (ie a near miss)

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

0 %

50%

75%

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.

In the event of a change in control event such as the Company merging or being taken over, the scorecard may be assessed and/or
re-set at the discretion of the Board. The Board may determine to make STIP payments to employees in the instance where the change in
control event occurs prior to the completion of the relevant performance year, in which case the STIP will be prorated in accordance with
the portion of the year worked.

An employee must have been with the Company for 3 months to qualify for any STIP. If the employee is with the Company for 3 months
but less than the full year the STIP is prorated according to the period of time the employee has been with the Company.

If an employee leaves the Company during a year (other than for retirement or due to redundancy) no STIP is payable. If the employee
retires or is made redundant then the STIP is prorated in accordance with the portion of the year worked.

STIP payments, if any, are made in October each year. Therefore any STIP payments for the year ended 30 June 2015 will be paid in
October 2015. 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 (respectively).

Directors’ Statutory Report
For the year ended 30 June 2015

4. Remuneration Report (Audited) continued

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

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 long term incentive plan 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).

The Company’s current long term incentive plan has been in operation since 2011 (2011 Plan). Following feedback from shareholders
at the Company’s 2014 Annual General Meeting, the directors conducted a review of the 2011 Plan including seeking independent advice
on the plan, as noted in Section 4.11. Following that review, the Company proposes to implement a new equity incentive plan to address
shareholder feedback and better align the Company’s long term incentive plan with its current strategy and objectives and current peer
group market practice (New EIP). Shareholders will be asked to approve the new plan at the 2015 Annual General Meeting.

In this reporting period, grants of performance rights were made under the 2011 Plan. Subject to shareholders approving the New EIP,
for the next reporting period, it is expected that future grants will be made under the New EIP. The key features of the current 2011 Plan
and the offer the Board proposes to make under the New EIP are set out in the following table.

Plan Feature

Vehicle

Current 2011 Plan

Performance Rights

Proposed offer - New EIP

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

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

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

Managing Director

120%

Managing Director

120%

Executive Director

Executives

95%

70%

Executive Director

Executives

Senior technical employee

50%

Senior technical employee

95%

70%

50%

Staff

30%

Performance Period

33% 1 year

33% 2 years

33% 3 years

Vesting Period

3 years

Staff will not participate in long term
incentive plan

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

Rationale for change: 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).

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.

Directors’ Statutory Report
For the year ended 30 June 2015

4. Remuneration Report (Audited) continued

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

Plan Feature

Current 2011 Plan

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:

<5 zero vests

5, 50% vests

3 or 4 partial vesting, 1 or 2, 100% vests

Proposed offer - New EIP

None (incorporated in STIP)

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 = pro rata
vesting

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

= or >90th percentile = 100% vesting

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.

Re-testing

Annually following initial test up until 3 years.

Rationale for change: 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
incentives are only achieved if Cooper Energy’s
performance exceeds that of its peers.

12 peer group companies: Beach Energy Limited;
Senex Energy Limited; Drillsearch 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.

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

1 retest only 12 months after original 3 year test
date

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

Vesting

Clawback

Vesting to the extent applicable 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.

Pro rata vesting based on service and
performance.

Directors’ Statutory Report
For the year ended 30 June 2015

4. Remuneration Report (Audited) continued

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

Plan Feature

Current 2011 Plan

Proposed offer - New EIP

Eligibility to participate

All employees

Management and senior technical staff

Rationale for change: 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

2% for each tranche

5% total on issue (excluding KMP).

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

4.7 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.

The Company’s remuneration profile for Executives is as follows:

Remuneration
Element

Expressed as percentage of total remuneration
at target level performance

Expressed as percentage of total remuneration
at maximum (super stretch) level performance

Managing
Director

Executive
Director

Executives

Managing
Director

Executive
Director

Executives

52%

24%

56%

23%

21%

57%

27%

16%

31%

38%

37%

28%

35%

45%

23%

32%

100%

Base

STI

LTI

Total

Directors’ Statutory Report
For the year ended 30 June 2015

4. Remuneration Report (Audited) continued

4.7 Relationship between remuneration framework and Company performance continued

Company performance – STIP and 2011 Plan results

For the reporting period to 30 June 2015, the Company’s performance was measured against Company KPIs which were set out in a
scorecard and weighted (as described in Section 4.6 above). The Company met or exceeded a number of its STIP KPIs but did not meet others:

STIP KPIs

2015 financial year performance Comment

HSEC Performance

Between base and target

Increased production from
existing assets

Below base

Growth in reserves and
resources

Super stretch

Cost management

Processes and
Risk Management

Stakeholder Relationships

Stretch

Performance in the area of safety was below the target set by the
Board but better than peers. However, there was strong performance
in the areas of process improvement, community and health.

The Company did not meet the base production target set by the
Board, mainly due to drilling activity in PRLs 85-104 and Indonesia
being undertaken later than forecast.

The Company exceeded targets in achieving key milestones in
its plans to establish a valuable gas business to supply eastern
Australia (see Operating and Financial Review under the heading
“Project and portfolio development” on page 28). 2P reserves were
increased significantly following the results of the Bunian-3 well in
Indonesia. (see Operating and Financial Review under the heading
“Reserves and resources” on page 29).

The Company responded quickly to lower oil prices and exceeded
cost targets. As the Company develops and evolves, fit for purpose
systems and processes continue to be developed, including prudent
to risk management

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 2015.

As described in Section 4.6 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.

Performance rights issued under the 2011 Plan vested for the first time in 2015. The Company’s absolute shareholder return and relative
shareholder return for the vesting period for performance rights granted on 2 January 2012 (2012 Award) were tested for the final
time on 29 September 2014 in accordance with the 2011 Plan rules. This resulted in a total of 2,669,814 performance rights held by
employees vesting (and the issue of 2,669,814 shares in the Company for nil consideration) and the cancellation of the remaining 223,478
performance rights granted in the reporting period to these employees as part of the 2012 Award. This equates to the vesting of a total of
92% of the 2012 Award performance rights.

4.8 Realised remuneration

The Company believes that reporting pay ‘actually realised’ (i.e. received) by Executives is useful to shareholders and provides clear and
transparent disclosure of remuneration paid by the Company.

The following table shows remuneration ‘actually realised’ by 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 on pages 36 to 49.

The table below sets out the STIP cash bonus that was actually paid to the Executive during the reporting period in respect of prior period
performance. In contrast, the amounts shown in the tables in Sections 4.14 and 4.15 represent an estimate of the bonus that the Executive
will receive in the subsequent financial year for their current reporting period performance, along with a true-up for any difference between
the amount accrued and the amount paid for the preceding period.

As a general principle, the Accounting Standards require a value to be placed on long term incentive awards based on probabilistic
calculations at the time of grant. This value is not relative to or indicative of the actual benefit (if any) that may ultimately be realised by
Executives if the performance hurdles are met and the performance rights vest. The table below sets out the value of the long term incentive
based on the closing price of the shares issued to the Executive on the date of vesting (if any).

Directors’ Statutory Report
For the year ended 30 June 2015

4. Remuneration Report (Audited) continued

4.8 Realised remuneration continued

Subsequent to this the price of the shares may rise or fall.

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. Glavas7

Year

Fixed
Remuneration1
$

STIP2

LTIP3

2015

2014

2015

2014

2015

2014

2015

2014

2015

2014

2015

2014

2015

2014

645,000

630,000

223,736

385,000

396,408

390,550

351,719

343,350

187,024

167,670

379,019

145,661

241,902

422,100

280,350

180,370

146,850

112,283

91,341

110,559

80,252

55,989

11,342

48,277

5,000

465,480

Other4

82,810

68,367

6,134

6,101

6,248

5,568

6,025

5,992

6,025

5,992

6,114

1,957

5,112

Total

1,615,390

978,717

410,240

537,951

514,939

487,459

468,303

429,594

249,038

185,004

433,410

147,618

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 2015 financial year in respect of

performance in the 2014 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 vested value of performance rights which vested during the reporting period, calculated

based on the share price on the date the performance rights were vested.

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 – from 1 March 2014) and accordingly his entitlements are prorated.

6 Ms Evans works part time (0.7 full time equivalent) and accordingly her entitlements are prorated.

7 Mr Glavas was appointed on 4 August 2014.

4.9 Options

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

Directors’ Statutory Report
For the year ended 30 June 2015

4. Remuneration Report (Audited) continued

4.10 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 expire 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.

4.11 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 2015 totalled $558. 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 2015 totalled $12,081.

Egan Associates was engaged by the Remuneration and Nomination Committee to provide advice regarding the terms of renewal of the
Managing Director’s contract of employment, including benchmarking of his remuneration package. Fees payable to Egan Associates for
this work totalled $14,784.

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

4.12 Accounting for performance rights

The value of the performance rights issued under the 2011 Plan is recognised as Share Based Payments in the Company’s statement of
comprehensive income and amortised over the vesting period.

Performance rights were granted on 1 December 2014. The performance 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 granted under the 2011 Plan 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).

Directors’ Statutory Report
For the year ended 30 June 2015

4. Remuneration Report (Audited) continued

4.12 Accounting for performance rights continued

The value of performance rights shown in the tables below are the accounting fair values for grants in the reporting period:

Recipient of
rights granted
under the 2011
Plan during the
reporting period

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

No. of rights
granted during
reporting period

Fair value
of rights at
grant date

1,448,737

419,825

517,929

460,914

239,634

496,689

338,039

$281,055

$81,446

$100,478

$89,417

$46,489

$96,358

$65,580

No. of rights
under 2011
Plan vested
during reporting
period

1,483,712

Nil

% of rights
under 2011
Plan vested
to 30 June
2015

25%

The vesting date of the performance rights granted on 1 December 2014 is 1 October 2017. The fair value of these rights is $0.194 per
right. These performance rights have a commencement date of 30 September 2014.

4.13 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:

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

Held at
1 July 2014

4,430,269

1,578,992

1,228,028

864,668

389,577

312,033

Granted

Lapsed

Vested

Held at
30 June 2015

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

Directors’ Statutory Report
For the year ended 30 June 2015

4. Remuneration Report (Audited) continued

4.13 Additional remuneration disclosures continued

Held at
1 July 2013

Granted

Lapsed

Vested

Held at
30 June 2014

2,965,705

1,464,564

728,731

850,261

698,412

399,059

153,782

529,616

465,609

235,795

312,033

4,430,269

1,578,992

1,228,028

864,668

389,577

312,033

Executive Directors

Mr D. Maxwell

Mr H. Gordon

Executives

Mr A. Thomas

Mr J. de Ross

Ms A. Evans

Mr I. MacDougall

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 2014

Purchases

Received on vesting
of performance rights

Sales

Held at
30 June 2015

Directors

Mr J. Conde AO

Mr D. Maxwell

Mr H. Gordon

Mr J. Schneider

Ms A. Williams

Executives

Mr J. de Ross

Directors

Mr J. Conde AO

Mr L. J. Shervington

Mr D. Maxwell

Mr H. Gordon

Mr J. Schneider

Ms A. Williams

Executives

Mr J. de Ross

250,000

1,263,190

173,608

300,000

30,000

200,000

Held at
1 July 2013

Purchases

250,000

405,933

1,013,190

173,608

300,000

250,000

200,000

1,483,712

Received on
vesting of performance
rights

Sales

250,000

2,746,902

173,608

300,000

30,000

200,000

Held at
30 June 2014

250,000

Resigned

1,263,190

173,608

300,000

200,000

Directors’ Statutory Report
For the year ended 30 June 2015

4. Remuneration Report (Audited) continued

4.14 Table of Directors’ remuneration for 2014 and 2015 financial years

Benefits

Short Term

Base
Salary &
Fees

STIP

Other
Short Term
Benefits (a)

Post
Employment

Superannuation

Share Based
Payment (b)

LTIP
Performance
Rights

1,942

Directors

Mr J. Conde AO

2015

146,119

Appointed as
Chairman on
25/02/13

2014

146,453

Mr L. Shervington

2015

Resigned on
07/11/13

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

Ms A. Williams

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

2014

34,325

2015

86,758

2014

89,627

2015

626,217

509,713

82,810

2014

612,225

315,000

68,367

2015

204,953

139,901

6,134

2014

367,225

139,018

6,101

2015

86,758

2014

70,557

1,158

Long
Term

Long
Service
Leave

Total

160,000

39,442

95,000

97,917

491,800

1,729,323

442,841

1,456,208

215,518

585,289

135,021

665,140

95,000

78,241

13,881

13,547

3,175

8,242

8,290

18,783

17,775

18,783

17,775

8,242

6,526

a) Other short term benefits include fringe benefits on accommodation, car parking and other benefits.

b) 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 4.12 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.

Directors’ Statutory Report
For the year ended 30 June 2015

4. Remuneration Report (Audited) continued

4.15 Table of Executives’ remuneration for 2014 and 2015 financial years

Benefits

Short Term

STIP

Base
Salary &
Fees

Long
Term

Post
Employment

Share Based
Remuneration(b)

Other
Short Term
Benefits (a)

Long
Service
Leave

Superannuation

Performance
Rights

Total

2015

377,625

153,256

6,248

2014

372,775

97,638

5,568

2015

332,936

135,551

6,025

2014

325,575

108,588

5,992

2015

168,241

67,961

6,025

2014

153,474

43,470

5,992

2015

360,236

146,660

6,114

2014

138,664

37,760

1,957

2015

224,684

97,799

5,112

2014

18,783

179,910

735,822

17,775

114,515

608,271

18,783

126,734

620,029

17,775

73,939

531,869

18,783

46,326

307,336

14,196

27,069

244,201

18,783

56,180

587,973

6,998

17,218

6,241

191,620

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
27/02/12 and as
Company Secretary
on 25/11/13

Ms A. Evans

Commenced as
Company Secretary
and Legal Counsel
(0.6 FT equivalent) on
21/02/12

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) In accordance with the requirements of the Accounting Standards, remuneration includes a proportion of the value of the equity-linked

End of remuneration report.

Directors’ Statutory Report
For the year ended 30 June 2015

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 “2016 Outlook”),
further information about likely developments in the operations of the Group and the expected results of those operations in future financial
years has not been included in this report because disclosure of the information would likely result in unreasonable prejudice to the
consolidated entity.

10. Directors’ interests

The relevant interest of each Director in ordinary shares and options over shares issued by the parent entity as notified by the Directors to
the Australian Stock Exchange in accordance with S205G(1) of the Corporations Act 2001, at the date of this reports is as follows:

Mr J. Conde AO

Mr D. Maxwell

Mr H. Gordon

Mr J. Schneider

Ms A. Williams

Cooper Energy Limited

Ordinary Shares

Performance Rights

250,000

2,746,902

173,608

300,000

30,000

4,231,293

1,998,817

11. Share options and performance rights

At the date of this report, there are no unissued ordinary shares of the parent entity under option.

At the date of this report, there are 17,023,996 outstanding performance rights granted to employees under the 2011 Plan.

12. Events after financial reporting date

Refer to Note 28 of the Notes to the Financial Statements.

13. Proceedings on behalf of the company

No person has applied to the Court under section 237 of the Corporations Act for leave to bring proceedings on behalf of the Company,
or to intervene in any proceedings to which the Company is a party for the purpose of taking responsibility on behalf of the Company for all
or part of the proceedings.

No proceedings have been brought or intervened in on behalf of Cooper Energy Limited with leave of the Court under section 237 of the
Corporations Act.

Directors’ Statutory Report
For the year ended 30 June 2015

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 104 and forms part of the Directors’ report for the financial year ended
30 June 2015.

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
$nil (2014: $nil).

18. Rounding

The Group is of a kind referred to in ASIC Class Order 98/0100 dated 10 July 1998 and in accordance with that Class Order, 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 17 August 2015

Cooper Energy Limited
and its controlled entities
Financial Statements

For the year ended 30 June 2015

5353

Consolidated Statement of Comprehensive Income
For the year ended 30 June 2015

Consolidated

2015
$000

2014
$000

Notes

Continuing Operations

Revenue from oil sales

Cost of sales

Gross profit

Other revenue

Exploration and evaluation expenditure written off

Finance costs

Impairment

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

Share of loss in associate

Administration and other expenses

(Loss) / Profit before tax

Income tax benefit / (expense)

Total tax benefit / (expense)

39,084

72,303

(25,032)

(26,056)

14,052

46,247

1,867

(2,342)

(495)

(22,642)

3,634

(166)

2,842

(1,261)

(296)

(3,064)

(12,696)

(13,258)

(18,788)

31,210

2,955

(9,028)

Net (loss) / profit after tax from continuing operations

(15,833)

22,182

Discontinued operations

Total loss for the year from discontinued operations

Total profit for the period attributable to members

Other comprehensive income/(expenditure)

Items that may be reclassified subsequently to profit or loss

Foreign currency translation reserve

Fair value movements on available for sale investments

Income tax effect on fair value movements

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

Other comprehensive income/(expenditure) for the period net of tax

(47,635)

(63,468)

(232)

21,950

1,059

(8,325)

1,346

(164)

5,796

(1,346)

7,471

3,064

(3,634)

(2,083)

7,350

Total comprehensive income/(loss) for the period attributable to members

(65,551)

29,300

Basic earnings per share from continuing operations

Diluted earnings per share from continuing operations

Basic earnings per share

Diluted earnings per share

cents

(4.8)

(19.2)

cents

6.7

6.5

6.7

6.4

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

Consolidated Statement of Financial Position
As at 30 June 2015

Assets

Current Assets

Cash and cash equivalents

Trade and other receivables

Inventory

Income tax receivable

Prepayments

Exploration Assets classified as held for sale

Total Current Assets

Non-Current Assets

Available for sale financial assets

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

Income tax payable

Exploration 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) / Retained profits

Total Equity

Consolidated

2015
$000

2014
$000

Notes

39,373

12,001

940

859

640

53,813

47,178

11,145

289

732

59,344

46,906

53,813

106,250

1,343

26,040

520

11,921

981

105,363

1,919

18,293

1,141

94,621

120,187

142,014

174,000

248,264

8,936

1,913

10,849

11,020

45,194

3,066

59,280

12,343

553

5,040

17,936

2,740

20,676

14,431

41,360

4,004

59,795

70,129

80,471

103,871

167,793

115,460

114,625

6,151

7,440

(17,740)

45,728

103,871

167,793

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

Consolidated Statement of Changes in Equity
For the year ended 30 June 2015

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

Shares issued

Balance at 30 June 2015

Issued Capital

Reserves

(Accumulated
Losses) /
Retained
Earnings

Total
Equity

$’000

114,625

835

115,460

7,440

(2,083)

1,629

(835)

6,151

45,728

167,793

(63,468)

(2,083)

(63,468)

(65,551)

1,629

(17,740)

103,871

Balance at 1 July 2013

Profit for the period

Other comprehensive income

Total comprehensive income for the period

Transactions with owners in their capacity as owners:

Share based payments

Transferred to issued capital

Shares issued

Balance at 30 June 2014

114,570

(1,138)

114,625

7,350

1,283

(55)

7,440

23,778

21,950

137,210

21,950

7,350

29,300

1,283

45,728

167,793

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 2015

Consolidated

2015
$000

2014
$000

Notes

Cash Flows from Operating Activities

Receipts from customers

Payments to suppliers and employees

Income tax (paid)/received

Interest received – other entities

Net cash from operating activities

Cash Flows from Investing Activities

Transfers of term deposits

Payment for available for sale financial assets

Receipts from sale of other property, plant & equipment

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

Payment for shares

Net cash flow used in financing activities

Net (decrease)/increase in cash held

Net foreign exchange differences

Cash and Cash Equivalents At 1 July

Cash and Cash Equivalents At 30 June

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

38,613

80,991

(33,065)

(32,431)

(5,062)

1,549

2,035

300

1,398

50,258

1,860

2,847

(273)

15,660

(62)

(13,189)

(41,456)

(4,470)

(9,763)

(1,877)

(5,967)

(10,175)

(46,503)

(55)

(8,140)

335

47,178

39,373

3,700

324

43,154

47,178

1. Corporate information

The consolidated financial report of Cooper Energy Limited (the parent entity) for the year ended 30 June 2015 was authorised for issue in
accordance with a resolution of the Directors on 14 August 2015.

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 note 5 of the Directors 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 available for sale financial assets 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 Class Order 98/0100. The Group is an entity to which the class order applies.

Significant event and transaction

On 16 December 2014 Cooper Energy Ltd announced the acquisition of a 50% interest in the Sole gas field and Orbost Gas Plant.
The acquisition was completed in May 2015. This acquisition consisted of one retention licence with undeveloped resources, the Orbost Gas
Plant and land and the assumption of abandonment liabilities relating to one appraisal well and the gas plant. For cash consideration of
$2.5 million and pre completion costs of $2.0 million, Cooper Energy made an asset acquisition consisting of the following:

• Sole exploration and evaluation asset $12.6 million

• Appraisal well abandonment liability $2.4 million

• Orbost Gas Plant and land abandonment liability $5.8 million

b) Statement of compliance

(i) Changes in accounting policy and disclosures

The financial report complies with Australian Accounting Standards and International Financial Reporting Standards (“IFRS”) as issued by
the International Accounting Standards Board.

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 – Offsetting Financial Assets and Financial Liabilities

• AASB 2013-3 Amendments to AASB 136 – Recoverable Amount Disclosure for Non-Financial Assets

• AASB 1031 Materiality

• AASB 2013-9 Amendments to Australian Accounting Standards – Conceptual Framework, Materiality and Financial Instruments

• AASB 2014-1 Part A -Annual Improvements 2010–2012 Cycle

• AASB 2014-1 Part A -Annual Improvements 2011–2013 Cycle

Adoption of these standard interpretations is described below:

Notes to the Financial StatementFor the year ended 30 June 20152. Summary of significant accounting policies continued

b) Statement of compliance continued

AASB 2012-3

Summary

Amendments to Australian Accounting Standards - Offsetting Financial Assets and
Financial Liabilities

AASB 2012-3 adds application guidance to AASB 132 Financial Instruments: Presentation to
address inconsistencies identified in applying some of the offsetting criteria of AASB 132, including
clarifying the meaning of "currently has a legally enforceable right of set-off" and that some gross
settlement systems may be considered equivalent to net settlement.

Application Date of the Standard 1 January 2014

Application date for Group

1 July 2014

Impact on Group financial report

The application of this standard has not resulted in any significant change in the 2015 year
end accounts.

AASB 2013-3

Amendments to AASB 136 – Recoverable Amount Disclosures for Non-Financial Assets

Summary

AASB 2013-3 amends the disclosure requirements in AASB 136 Impairment of Assets.
The amendments include the requirement to disclose additional information about the fair value
measurement when the recoverable amount of impaired assets is based on fair value less costs
of disposal.

Application Date of the Standard 1 January 2014

Application date for Group

1 July 2014

Impact on Group financial report

The application of this standard has not resulted in any significant change in the 2015 year
end accounts.

AASB 1031

Summary

Materiality

The revised AASB 1031 is an interim standard that cross-references to other Standards and
the Framework (issued December 2013) that contain guidance on materiality. AASB 1031
will be withdrawn when references to AASB 1031 in all Standards and Interpretations have
been removed

Application Date of the Standard 1 January 2014

Application Date for Group

1 July 2014

Impact on Group Financial report The application of this standard has not resulted in any significant change in the 2015 year end

accounts.

AASB 2013-9

Summary

Amendments to Australian Accounting Standards – Conceptual Framework, Materiality
and Financial Instruments

The Standard contains three main parts and makes amendments to a number Standards and
Interpretations.

Part A of AASB 2013-9 makes consequential amendments arising from the issuance of AASB
CF 2013-1.

Part B makes amendments to particular Australian Accounting Standards to delete references to
AASB 1031 and also makes minor editorial amendments to various other standards.

Part C makes amendments to a number of Australian Accounting Standards, including
incorporating Chapter 6 Hedge Accounting into AASB 9 Financial Instruments.

Application Date of the Standard 1 January 2014

Application Date for Group

1 July 2014

Impact on Group Financial report The application of this standard has not resulted in any significant change in the 2015 year

end accounts.

Notes to the Financial StatementFor the year ended 30 June 20152. Summary of significant accounting policies continued

b) Statement of compliance continued

AASB 2014-1

Part A -Annual Improvements

2010–2012 Cycle

Summary

AASB 2014-1 Part A: This standard sets out amendments to Australian Accounting Standards
arising from the issuance by the International Accounting Standards Board (IASB) of International
Financial Reporting Standards (IFRSs) Annual Improvements to IFRSs 2010–2012 Cycle and
Annual Improvements to IFRSs 2011–2013 Cycle.

Annual Improvements to IFRSs 2010–2012 Cycle addresses the following items:

• AASB 2 - Clarifies the definition of ‘vesting conditions’ and ‘market condition’ and introduces the

definition of ‘performance condition’ and ‘service condition’.

• AASB 3 - Clarifies the classification requirements for contingent consideration in a business

combination by removing all references to AASB 137.

• AASB 8 - Requires entities to disclose factors used to identify the entity’s reportable segments when
operating segments have been aggregated. An entity is also required to provide a reconciliation of
total reportable segments’ asset to the entity’s total assets.

• AASB 116 & AASB 138 - Clarifies that the determination of accumulated depreciation does not

depend on the selection of the valuation technique and that it is calculated as the difference between
the gross and net carrying amounts.

AASB 124 - Defines a management entity providing KMP services as a related party of the
reporting entity. The amendments added an exemption from the detailed disclosure requirements
in paragraph 17 of AASB 124 for KMP services provided by a management entity. Payments made
to a management entity in respect of KMP services should be separately disclosed.

Application Date of the Standard 1 July 2014

Application Date for Group

1 July 2014

Impact on Group Financial report The application of this standard has not resulted in any significant change in the 2015 year end

accounts.

AASB 2014-1

Part A -Annual Improvements

2011–2013 Cycle

Summary

Annual Improvements to IFRSs 2011–2013 Cycle addresses the following items:

• AASB13 - Clarifies that the portfolio exception in paragraph 52 of AASB 13 applies to all
contracts within the scope of AASB 139 or AASB 9, regardless of whether they meet the
definitions of financial assets or financial liabilities as defined in AASB 132.

• AASB 140 - Clarifies that judgment is needed to determine whether an acquisition of investment
property is solely the acquisition of an investment property or whether it is the acquisition of a
group of assets or a business combination in the scope of AASB 3 that includes an investment
property. That judgment is based on guidance in AASB 3.

Application Date of the Standard 1 July 2014

Application Date for Group

1 July 2014

Impact on Group Financial report The application of this standard has not resulted in any significant change in the 2015 year

end accounts.

(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 2015,
are outlined below:

Notes to the Financial StatementFor the year ended 30 June 20152. Summary of significant accounting policies continued

b) Statement of compliance continued

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 2014-10

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 20152. 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 20152. 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 adoption of this standard 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.

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

(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 2017

Application Date for Group

The International Accounting Standards Board (IASB) in its July 2015 meeting decided to confirm
its proposal to defer the effective date of IFRS 15 (the international equivalent of AASB 15) from
1 January 2017 to 1 January 2018. The amendment to give effect to the new effective date for
IFRS 15 is expected to be issued in September 2015. At this time, it is expected that the AASB
will make a corresponding amendment to AASB 15, which will mean that the application date of
this standard for the Group will move from 1 July 2017 to 1 July 2018.

Impact on Group Financial report The group is currently assessing the impact of this standard however, given the small number of

individual contracts currently in place the Group expects the impact will be minimised.

Notes to the Financial StatementFor the year ended 30 June 20152. Summary of significant accounting policies continued

b) Statement of compliance continued

AASB 9

Summary

Financial Instruments

AASB 9 (December 2014) is a new Principal standard which replaces AASB 139. This new Principal
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 application. The own credit changes can be early applied in isolation without
otherwise changing the accounting for financial instruments.

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.

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.

AASB 9 includes requirements for a simpler approach for classification and measurement of
financial assets compared with the requirements of AASB 139.

The main changes are described below.
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.

d) 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 caused
by the deterioration of an entity’s own credit risk on such liabilities are no longer recognised in
profit or loss.

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 Group intends to early adopt AASB 9 from 1 July 2015 and has performed an initial

assessment of the impacts to the financial report. The material impacts include:
• treating the available for sale financial assets as fair value through other comprehensive income, with
no impairment of these assets or recycling of amounts in other comprehensive income on disposal;
and

• using the amended hedge accounting rules for the Group’s collar options which would be classified

as fair value through other comprehensive income.

The standard is planned to be applied prospectively. No other material changes are expected from
its application.

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

Notes to the Financial StatementFor the year ended 30 June 20152. Summary of significant accounting policies continued

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 139
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 139, 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.

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.

Notes to the Financial StatementFor the year ended 30 June 2015
2. Summary of significant accounting policies continued

f) Foreign currency continued

Other than Sukananti Ltd, which has a US dollar functional currency, all other foreign operations of the group have an Australian dollar
functional currency.

g) Investments

Available-for-sale Investments

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.

For investments that are actively traded in organised financial markets, fair value is determined by reference to stock exchange quoted
market bid prices at the close of business on the Consolidated Statement of Financial Position date. Where investments are not actively
traded, fair value is established by using other market accepted valuation techniques.

Investments in associates

Investments in associates are initially recognised at cost. Any surplus over the Group’s share in the associates net assets on acquisition is
accounted for as goodwill; any deficit is treated as an accounting gain and recognise immediately in the income statement.

After initial recognition, the Group recognises its share of the associated profit or loss.

h) Revenue and cost recognition

Revenue is recognised and measured at fair value of consideration received or receivable to the extent that it is probable that the economic
benefits will flow to the Group and the revenue can be reliably measured. The following specific recognition criteria must also be met before
revenue is recognised:

Revenues and costs from production sharing contracts

Revenue earned and production costs incurred from a production sharing contract are recognised when title to the product passes to the
customer and is based upon the Group’s share of sales and costs relating to oil production that are allocated to the Group under the contract.

Interest revenue

Interest revenue is recognised as interest accrues (using the effective interest method, 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 best 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.

Notes to the Financial StatementFor the year ended 30 June 20152. Summary of significant accounting policies continued

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, 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 granted excludes the impact of any non-market vesting
conditions (for example, profitability and sales growth targets).

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

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

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

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

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

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

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

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

If an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation, and any expense not yet recognised for the
award is recognised immediately. However, if a new award is substituted for the cancelled award and designated as a replacement award on
the date that it is granted, the cancelled and new award are treated as if they were a modification of the original award, as described in the
previous paragraph.

The dilutive effect, if any, of outstanding performance rights 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.

Notes to the Financial StatementFor the year ended 30 June 20152. Summary of significant accounting policies continued

m) Income tax continued

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.

Deferred income tax assets and liabilities are measured at the tax rates that were expected to apply to the year when the asset is realised
or the liability is settled, based on tax rates and tax laws that have been enacted or substantively enacted at the Consolidated Statement of
Financial Position date.

Income taxes relating to items recognised directly in equity are recognised in equity and not in profit or loss.

Deferred tax assets and deferred tax liabilities are offset only if a legally enforceable right exits to offset current tax assets against current
tax liabilities and the deferred tax asset and liabilities relate to the same taxable entity and the same taxation authority.

n) Other taxes

Goods and Services Taxes (“GST”)

Revenues, expenses and assets are recognised net of the amount of Goods and Services Taxes (“GST”) except:-

• where the GST incurred on a purchase of goods and services is not recoverable from the taxation authority, in which case the GST is

recognised as part of the cost of acquisition of the asset or as part of the expense item as applicable; and

• receivables and payables are stated with the amount of GST included.

The net amount of GST recoverable from, or payable to, the taxation authority is included as part of receivables or payables in the
Consolidated Statement of Financial Position.

Cash flows are included in the Cash Flow Statement on a net basis and the net GST component of cash flows arising from investing and
financing activities, which is recoverable from, or payable to, the taxation authority, are classified as operating cash flows.

Commitments and contingencies are disclosed net of the amount of GST recoverable from, or payable to, the taxation authority.

Petroleum Resource Rent Tax (PRRT)

For PRRT purposes, the impact of future augmentation on expenditure is included in the determination of future taxable profits when
assessing the extent to which a deferred tax asset can be recognised in the statement of financial position. Deferred tax assets are reduced
to the extent that it is no longer probable that the related tax benefit will be realised. The Group has lodged starting base returns for all
exploration and production areas. In June 2013, participants including the Company were granted a combination certificate for the Cooper
Basin projects essentially deeming PEL 92 and PEL 93 to be a single project for PRRT purposes.

o) Exploration and evaluation expenditure

Exploration and evaluation expenditure is accounted for in accordance with the area of interest method and is capitalised to the extent that:

i. the rights to tenure of the areas of interest are current and the Group controls the area of interest in which the expenditure has

been incurred; and

ii. such costs are expected to be recouped through successful development and exploration of the area of interest, or alternatively

by its sale; or

iii. exploration and evaluation activities in the area of interest have not at the reporting date:

a. reached a stage which permits a reasonable assessment of the existence or otherwise of economically recoverable reserves; and
b. active and significant operations in, or in relation to, the area of interest are continuing.

Notes to the Financial StatementFor the year ended 30 June 20152. Summary of significant accounting policies continued

o) Exploration and evaluation expenditure continued

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.

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 asset and then depreciated
over the producing life of the asset. Any change in the discount rate is applied prospectively.

These estimated costs, whilst based on anticipated technological and legal requirements, assume no significant changes will occur in
relevant State, Federal and International legislation.

r) Property, plant and equipment

Property, plant and equipment are stated at historical cost less accumulated depreciation and any accumulated impairment losses. Historical
cost includes expenditure that is directly attributable to the acquisition of the items.

Subsequent costs are included in the asset’s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that
future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. All other repairs
and maintenance are charged to the Consolidated Statement of Comprehensive Income during the financial period in which they are incurred.

The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at each Consolidated Statement of Financial Position
date. The carrying values of property, plant and equipment are reviewed for impairment at each reporting date, with recoverable amount
being estimated when events or changes in circumstances indicate that the carrying value may be impaired. The recoverable amount
of property, plant and equipment is the higher of fair value less cost to sell and value in use. For an asset that does not generate largely
independent cash flows, recoverable amount is determined for the cash generating unit to which the asset belongs, unless the asset’s value
in use can be estimated to be close to its fair value.

An asset’s or cash generating unit’s carrying amount is written down immediately to its recoverable amount if the asset’s or cash generating
unit’s carrying amount is greater than its estimated recoverable amount.

Gains and losses on disposals are determined by comparing proceeds with the carrying amount. These are included in the statement of
comprehensive income.

An item of property, plant and equipment is de-recognised upon disposal or when no further future economic benefits are expected from its
use. Any gains or losses arising on de-recognition of the asset (calculated as the difference between the net disposal proceeds and the net
carrying amount of the asset) is included in the statement of comprehensive income in the period the asset is de-recognised.

Notes to the Financial StatementFor the year ended 30 June 20152. Summary of significant accounting policies continued

s) Impairment of non-current assets

Assets that are subject to amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the
carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset’s carrying amount exceeds
its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs to sell and value in use. For the purposes of
assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash generating units).
In assessing value-in-use, the estimated future cash flows are discounted to their present value using a pre-tax rate that reflects current
market assessments of the time value of money and the risks specific to the asset.

t) Cash and cash equivalents

Cash and short term deposits in the Consolidated Statement of Financial Position comprise cash at bank and short term deposits with an
original maturity of twelve 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 when there is objective evidence that the Group will not be able to collect the debts. Financial
difficulties of the debtor, default payments or debts more than 90 days overdue are considered objective evidence of impairment. The
amount of the impairment loss is the receivable carrying amount, compared to the present value of estimated future cash flows, discounted
at the original effective interest rate. Bad debts are written off when identified.

v) Inventory

Inventories are carried at the lower of their cost or net realisable value. Inventories held by the group are in respect of stores and spares
involved in drilling operations.

w) Trade and other payables

Trade payables and other payables are carried at amortised costs and represent liabilities for goods and services provided to the Group
prior to the end of the financial year that are unpaid and arise when the Group becomes obliged to make future payments in respect of the
purchase of these goods and services.

x) Provisions

Provisions are recognised when the Group has a legal or constructive obligation to make a future sacrifice of economic benefits to other
entities as a result of past transactions or other past events, it is probable that a future sacrifice of economic benefits will be required and a
reliable estimate can be made of the amount of the obligation.

Provisions are not recognised for future operating losses. Where there are a number of similar obligations, the likelihood that an outflow will
be required in settlement is determined by considering the class of obligations as a whole. A provision is recognised even if the likelihood of
an outflow with respect to any one item included in the same class of obligations may be small.

y) Contributed equity

Issued and paid up capital is recognised as the fair value of the consideration received by the Group.

Any transaction costs arising on the issue of ordinary shares 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. Movement in the derivative’s fair value
is taken directly to profit or loss. The Group does not use hedge accounting.

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

Notes to the Financial StatementFor the year ended 30 June 20152. Summary of significant accounting policies continued

bb) Significant accounting judgements, estimates and assumptions continued

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.

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.

(i) Significant accounting judgements continued

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.

Notes to the Financial StatementFor the year ended 30 June 20152. Summary of significant accounting policies continued

bb) Significant accounting judgements, estimates and assumptions continued

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.

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 throughout the world 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 quarterly basis. Resources are allocated
between each segment on an as needs basis. Selective reporting is provided to the Board quarterly 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
Indonesian 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 located in
South Australia. 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 six 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.

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.

European Business Unit

The Company has disposed of all exploration interests in Poland and is in the process of winding up the Polish and Dutch subsidiaries.

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 20153. Segment reporting continued

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

Geographical Segments

Australian
Business
Unit

African
Business Unit
(Disc. Ops.)

Asian
Business
Unit

European
Business Unit
(disc. Ops)

Elimination

Consolidated

$’000

Year ended 30 June 2015

Revenue

Interest and other revenue

Total consolidated revenue

Depreciation of property

Amortisation of:

- Development costs

- Exploration costs

Impairment

Finance costs

Share based payments

Exploration costs written off

33,510

2,423

35,933

(397)

(5,256)

(771)

(22,642)

(495)

(1,629)

(2,342)

5,574

(72)

(2,248)

(556)

39,084

1,867

40,951

(469)

(7,504)

(771)

(22,642)

(495)

(1,629)

(2,342)

Segment result

(17,670)

(47,657)

(562)

(556)

(66,423)

Income tax

Net Profit

Segment liabilities

Segment assets

Non-Current Assets

Cash flow from:

67,168

148,001

101,972

1,521

318

- Operating activities

5,802

(1,503)

- Investing activities

- Financing

(12,862)

325

1,675

25,902

18,215

(2,132)

2,219

Capital Expenditure

(18,966)

(392)

(8,064)

(132)

141

(235)

2,955

(63,468)

70,129

174,000

120,187

2,035

(10,175)

(27,422)

Notes to the Financial StatementFor the year ended 30 June 2015

3. Segment reporting continued

Geographical Segments

Australian
Business
Unit

African
Business Unit
(Disc. Ops.)

Asian
Business
Unit

European
Business Unit
(disc. Ops)

Elimination

Consolidated

$’000

Year ended 30 June 2014

Revenue

Other revenue

Total consolidated revenue

Depreciation of property

Amortisation of:

- Development costs

- Exploration costs

Impairment

Finance costs

Share based payments

Exploration costs written off

66,457

3,973

70,430

(434)

(4,943)

(1,112)

(3,064)

(296)

(1,283)

(1,261)

5,846

(52)

(707)

(1,131)

Segment result

30,164

(17)

2,177

(215)

(1,131)

Income tax

Net Profit

Segment liabilities

Segment assets

Non-Current Assets

Cash flow from:

75,767

185,825

129,555

2,670

46,844

- Operating activities

48,100

688

- Investing activities

(19,529)

(22,149)

- Financing

(55)

1,963

15,533

12,703

1,360

(4,645)

Capital Expenditure

(22,351)

(22,149)

(4,620)

Revenue from external customers by geographical location of production

110

(180)

72,303

2,842

75,145

(486)

(5,650)

(1,112)

(3,064)

(296)

(1,283)

(1,261)

30,978

(9,028)

21,950

80,471

248,264

142,014

50,258

(46,503)

(55)

(49,300)

Australia

Indonesia

Total revenue

Revenue from one customer amounted to $32,220,000 (2014: $63,983,000) arising from oil sales.

2015
$’000

2014
$’000

33,510

66,457

5,574

5,846

39,084

72,303

Notes to the Financial StatementFor the year ended 30 June 2015

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 income

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

Finance cost of success fee

Fair value adjustment of success fee liability

Total finance costs

Administration and other expenses

Depreciation of property, plant and equipment

General administration (includes employee benefits and lease payments)

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

Realised and unrealised foreign currency translation gain/(loss)

Total other expenses

Employee benefits expense

Director and employee benefits

Share based payments

Superannuation expense

Lease payments

Minimum lease payment – operating lease

Consolidated

2015
$’000

2014
$’000

39,084

72,303

1,225

1,360

281

361

1,867

1,482

2,842

(13,464)

(12,814)

(3,293)

(6,480)

(771)

(1,112)

(7,504)

(5,650)

(25,032)

(26,056)

(1,433)

(310)

1,248

(495)

(257)

(39)

(296)

(469)

(486)

(12,931)

(12,423)

(206)

946

(349)

(12,696)

(13,258)

(5,067)

(5,401)

(1,629)

(1,283)

(364)

(315)

(7,060)

(6,999)

(326)

(99)

Notes to the Financial StatementFor the year ended 30 June 20155. Income tax

The major components of income tax expense are:

Consolidated Statement of Comprehensive Income

Current income tax

Current income tax charge

Adjustments in respect of prior year income tax1

Deferred income tax

Origination and reversal of temporary differences

Income tax expense

Petroleum Resource Rent Tax - deferred tax

Total tax expenses

Numerical reconciliation between tax expense and pre-tax net profit

Accounting (loss)/profit before tax from continuing operations

Income tax using the domestic corporation tax rate of 30% (2014: 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

Income tax expense

Income tax recognised in other comprehensive income

Revaluation of available for sale financial assets

Income tax using the domestic corporation tax rate of 30% (2014: 30%)

Consolidated

2015
$’000

2014
$’000

(5,040)

847

2,108

2,955

290

(4,750)

(4,278)

(9,028)

2,955

(9,028)

(18,788)

31,210

5,636

(9,363)

1,055

(2,957)

(1,411)

(1,346)

1,346

826

(259)

(2,681)

290

110

335

2,955

(9,028)

1,346

(1,346)

1 During the period, the Group submitted a claim in respect to research and development spent in prior periods. This resulted in an

amendment to the 2014 income tax return – a refund of $0.8 million was received in July 2015.

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 20155. Income tax continued

Unrecognised temporary differences

At 30 June 2015, 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 (2014 $nil).

Franking Tax Credits

At 30 June 2015 the parent entity had franking tax credits of $43,715,169 (2014: $38,663,576). The fully franked dividend equivalent is
$102,002,060 (2014 $90,215,011).

PRRT

Cooper Energy Limited has not recognised a Deferred Tax Asset for the Petroleum Rent Resource Tax of $22,341,000 (2014:
$19,071,000) on the basis that it has a significant level of undeducted expenditure and nil PRRT payments projected in the future. As
stated in note 28, Events after the reporting period, through the BMG Joint Venture the Group plans to submit applications to revert the
existing licenses to petroleum retention leases. This reversion may have an impact on the Group’s ability to carry forward the unused PRRT
credits in respect of BMG, which if lost would result in the recognition of a deferred tax liability of approximately $1,000,000.

Income Tax Losses

(a) Revenue Losses

Cooper Energy Limited has recognised a Deferred Tax Asset for the year ended 30 June 2015 of $676,797 (2014: nil). All prior recognised
Deferred Tax Assets have been fully utilised during the prior financial years.

(b) Capital Losses

Cooper Energy has not recognised a Deferred Tax Asset for Australian income tax capital losses of $22,207,705 (2014: $15,987,262) on
the basis that it is not probable that the carried forward capital losses will be utilised against future assessable capital profits.

Consolidated
Statement of
Financial Position

Consolidated Statement
of Comprehensive
Income

2015
$’000

2014
$’000

2015
$’000

2014
$’000

Deferred income tax from corporate tax

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

Deferred tax liabilities

Trade and other receivables

Available for sale financial assets

Oil properties

Exploration and evaluation

Provisions

Unrealised currency translation gain

Deferred tax assets

Property, plant & equipment

Oil properties

Trade and other payables

Provision for employee entitlements

Provisions

Other

Tax losses

1,574

1,790

216

1,624

11,706

12,637

416

144

122

13,840

16,173

1,296

681

125

677

512

1,173

2,820

1,742

931

(416)

(22)

(3)

1,296

(13)

169

(1,173)

168

677

1,826

919

849

(4,751)

(3)

(97)

388

(3,499)

Deferred tax income (expense)

3,454

(4,278)

Deferred tax liability from corporate tax

11,020

14,431

Notes to the Financial StatementFor the year ended 30 June 20155. Income tax continued

Deferred income tax from petroleum resource rent tax

Deferred income tax 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

2015
$’000

2014
$’000

2015
$’000

2014
$’000

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

11,020

14,431

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 2015 there exists performance rights that if
vested in full, would result in the issue of 17,276,975 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:

Consolidated

2015
$’000

2014
$’000

Net profit/(loss) attributable to ordinary equity holders of the parent from continuing operations

(15,833)

22,182

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)

2015
Thousands

2014
Thousands

330,905

329,377

330,905

341,666

(4.8)

6.7

6.5

Notes to the Financial StatementFor the year ended 30 June 20156. Earnings per share continued

Net profit/(loss) attributable to ordinary equity holders of the parent from continuing and
discontinued operations

Weighted average number of ordinary shares for basic earnings per share

Weighted average number of ordinary shares adjusted for the effect of dilution

Basic earnings per share for the period (cents per share)

Diluted earnings per share for the period (cents per share)

Consolidated

2015
$’000

2014
$’000

(63,468)

21,950

330,905

329,377

330,905

341,666

(19.2)

6.7

6.4

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)

Non-Current Assets

Term deposits at bank (ii)

Consolidated

2015
$’000

7,380

31,993

39,373

2014
$’000

7,671

39,507

47,178

1,919

(i) Short term deposits at the banks are in Australian dollars and are for periods of up to 3 months and earn interest at money market

interest rates.

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

The Company has a bilateral facility agreement for bank facilities totalling $40 million with Westpac Banking Corporation. Tranche A
$10 million is committed to 30 September 2015 and is available for issuing bank guarantees and cash advances (sub limit $5 million
for each item). As at 30 June 2015 bank guarantees of $3,906,000 (2014: $2,627,000) in relation to performance bonds on
exploration permits were issued against the facility. Tranche B $30 million is committed to 30 June 2017 and is available for draw
down subject to the satisfaction of certain conditions precedent. The Westpac facilities are currently being restructured from
corporate to reserve based lending and it is expected this will be completed before 30 September 2015.

Notes to the Financial StatementFor the year ended 30 June 20157. 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

Impairment of Non-Current Assets

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

(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

(Decrease)/increase in held for sale assets

Net cash from operating activities

Consolidated

2015
$’000

2014
$’000

(63,468)

21,950

7,504

771

469

2,342

70,127

166

(3,634)

5,650

1,112

486

1,261

3,064

1,629

1,283

496

(444)

(856)

(651)

(3,411)

(3,407)

(5,899)

(140)

349

296

607

8,556

(85)

1,051

5,040

100

(138)

2,035

50,258

Notes to the Financial StatementFor the year ended 30 June 20158. Trade and other receivables (current)

Trade receivables (i)

Related party receivables (ii)

Related party receivables – joint ventures (iii)

Interest receivable

Consolidated

2015
$’000

2014
$’000

11,406

10,009

238

201

156

787

217

132

12,001

11,145

(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 (current)

Bank facility fee

Insurance

Consolidated

2015
$’000

316

324

640

2014
$’000

333

399

732

10. Exploration assets held for sale and discontinued operations

In June 2013 the Board resolved to dispose of its exploration assets in Tunisia and during the 2012 financial year resolved to dispose of its
exploration assets in Poland. The divestment process relating to Tunisia is yet to generate acceptable offers therefore the Group is seeking
to defer and limit further capital expenditure and has advised the Tunisian Government of its intention to not extend or renew the Nabeul
permit and is continuing efforts to divest the Bargou and Hammamet permits. The liquidation of the Polish entities is progressing.

The losses from the exploration assets classified as held for sale are presented on a separate line in the Consolidated Statement of
Comprehensive Income.

During the financial year the company impaired E&E in respect of the Tunisian assets. The Tunisian and Polish entities activities are
classified as discontinued operations at June 2015.

Exploration and evaluation assets held for sale

Liabilities associated with assets held for sale

Net assets directly associated with disposal group

Consolidated

2015
$’000

2014
$’000

46,906

(2,740)

44,166

Loss for the year from discontinued operations

(150)

(232)

Impairment loss recognised on the re-measurement to fair value

Loss for the year from discontinued operations

Basic (loss)/earnings per share from discontinued operations (cents per share)

Diluted (loss)/earnings per share from discontinued operations (cents per share)

(47,485)

(47,635)

(14.4)

(232)

(0.07)

Notes to the Financial StatementFor the year ended 30 June 2015
11. Available for sale investments (non-current)

Shares at fair value

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

Opening balance

Purchases

Reclassification as investment in associate

Fair value movement

Sale of investment

Closing balance

12. Investments in associate (non-current)

Consolidated

2015
$’000

1,343

2014
$’000

26,040

20,182

(712)

(8,325)

5,796

(15,660)

1,343

26,040

The group has a 21.55% (2014: 22.9%) 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. In prior period the investment was classified as available for sale – during the 2015
financial year Cooper obtained significant influence over the investment following the election of one of the Group’s board members to the
board of BAS and therefore commenced accounting for the investment as an investment in associate. The following table illustrates the
summarised preliminary and unaudited financial information of the Group’s investment in Bass Strait Oil Company Limited at 30 June 2015:

Consolidated

2015
$’000

841

4,279

(163)

4,957

1,068

(18)

(530)

520

(802)

(35)

(837)

(166)

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

Group’s carrying amount of the investment

Loss before tax

Income tax expense

Loss for the year (continuing operations)

Total comprehensive expenditure for the year (continuing operations)

Group’s share of loss for the year

The associate had no contingent liabilities at 30 June 2015.

The investment in associate has been impaired and is carried at fair value.

Notes to the Financial StatementFor the year ended 30 June 201513. Oil properties (non-current)

Regions of focus

Australia

Asia

Africa

Europe

Total oil properties

Consolidated

Year end 30 June 2015

Carrying amount at 1 July 2014

Additions

Foreign currency adjustment

Depreciation

Impairment

Consolidated

2015
$’000

7,624

4,297

2014
$’000

16,778

1,515

11,921

18,293

Transferred Exploration

and Evaluation Development

$’000

Total

$’000

2,438

15,855

18,293

111

(771)

9,244

(7,504)

(7,484)

9,355

(8,275)

(7,484)

Carrying amount at 30 June 2015

1,778

10,143

11,921

As at 30 June 2015

Cost

Accumulated depreciation & impairment

Year end 30 June 2014

Carrying amount at 1 July 2013

Additions

Foreign currency adjustment

Depreciation

Carrying amount at 30 June 2014

As at 30 June 2014

Cost

Accumulated depreciation

5,174

35,356

40,530

(3,396)

(25,213)

(28,609)

1,778

10,143

11,921

3,289

14,127

261

(1,112)

2,438

7,301

17,416

7,562

(5,650)

(6,762)

15,855

18,293

5,063

26,080

31,143

(2,625)

(10,225)

(12,850)

2,438

15,855

18,293

Notes to the Financial StatementFor the year ended 30 June 201514. 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

2015
$’000

2014
$’000

(7,471)

(3,064)

(530)

(7,157)

(7,484)

(22,642)

(3,064)

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

Exploration and Evaluation Impairment

During the period the Group’s exploration assets in the Otway basin were reviewed. As a result of this review, the Otway basin Area of
Interest was refined into several Areas of Interest being:

• Otway onshore deep troughs

• PEL 168

• PEL 186

• PEP 151

Following this review and assessment, PEL 186 and PEP 151were fully impaired as they were not considered to be prospective. The total
impairment recognised in respect of exploration assets was $7.2m.

Oil Properties Impairment

A number of factors represented indicators of impairment as at 30 June 2015, including a significant decline in the oil price throughout the
period. As a result, the Group assessed the recoverable amounts of its Cash Generating Units (CGUs).

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 and 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:

30 June 2015

30 June 2014

Real oil price (US$ per bbl)

2016-2018

$65 increasing
to $75

Long term
(2019 +)

$80

AUD:USD exchange rate

$0.80

2015-2018

Long term
(2019 +)

$100
decreasing
to $95

$0.90
decreasing
to $0.85

$95

$0.85

CPI (%)

Pre-tax real discount rate (%)

2.5%

AUD assets 11.2%
USD assets 15.0%

AUD assets 10.4%
USD assets 15.0%

Notes to the Financial StatementFor the year ended 30 June 2015

14. Impairment continued

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 was reduced to nil and an impairment loss of $7.5 million was
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 and Sukananti. The results of this testing
indicated that the CGU’s recoverable amount was higher than their carrying amount. No impairment was recognised in respect of PEL 92
or Sukananti.

15. Other property, plant & equipment (non-current)

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

Consolidated

2015
$’000

2014
$’000

1,141

237

(397)

981

2,142

(1,161)

981

1,464

281

(118)

(486)

1,141

1,919

(778)

1,141

Notes to the Financial StatementFor the year ended 30 June 201516. Exploration and evaluation (non-current)

Regions of focus

Australia

Asia

Africa

European

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

Expenditure

Exploration acquired

Transferred to oil properties

Unsuccessful exploration wells written off (i)

Impairment

Exploration expenditure classified as held for sale

Carrying amount at 30 June

Consolidated

2015
$’000

2014
$’000

91,489

13,874

83,702

10,919

105,363

94,621

30,846

7,750

45,747

12,602

42,443

(111)

(261)

(2,342)

(1,261)

(7,157)

(22,893)

105,363

94,621

(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 2015
17. Trade and other payables (current)

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

18. Provisions (non-current)

Current Liabilities

Restoration provision

Employee provisions

Other provisions

Non-Current Liabilities

Long service leave provision

Restoration provision

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

2015
$’000

1,400

3,636

5,036

3,900

8,936

2014
$’000

4,951

2,117

7,068

5,275

12,343

Consolidated

2015
$’000

1,500

391

1,913

145

45,049

45,194

41,256

(5,772)

8,132

1,433

2014
$’000

509

553

104

41,256

41,360

3,321

1,077

36,601

257

45,049

41,256

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 2015 equalled 2.98% (2014: 3.7%) reflecting the Australian
Government 10 year bond rate.

Notes to the Financial StatementFor the year ended 30 June 201519. Financial liabilities (non-current)

Success fee financial liability

Movement in carrying amount of the success fee financial liability:

Carrying amount at 1 July

Obligation through BMG asset acquisition

Finance cost

Fair value adjustment

Carrying amount at 30 June

Consolidated

2015
$’000

3,066

4,004

310

(1,248)

2014
$’000

4,004

3,965

3,066

4,004

The discount rate used in the calculation of the liability as at 30 June 2015 equalled 2.98% (2013: 3.7%) reflecting the Australian
Government 10 year bond rate.

20. Contributed equity and reserves

Share capital

Ordinary shares

Issued and fully paid

Effective 1 July 1998, the Corporations legislation in place abolished the concepts of authorised
capital and par value shares. Accordingly, the Parent does not have authorised capital or par value in
respect of its issued shares.

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

Movement in ordinary shares on issue

At 1 July 2014

Issuance of shares for Performance Rights

At 30 June 2015

Consolidated

2015
$’000

2014
$’000

115,460

114,625

Thousands

$’000

329,236

114,625

2,669

835

331,905

115,460

Notes to the Financial StatementFor the year ended 30 June 201520. Contributed equity and reserves continued

Reserves

Consolidation
reserve
$’000

Foreign
Currency
Translation
Reserve
$’000

Share
based
payment
reserve
$’000

Option
premium
reserve
$’000

Available
for sale
investment
reserve
$’000

Total
$’000

(541)

3,750

(4,372)

(1,138)

(541)

(164)

1,059

(541)

895

(55)

1,283

4,978

(835)

1,629

5,772

7,514

3,142

7,350

(55)

1,283

7,440

(3,142)

(2,083)

(835)

1,629

6,151

Consolidated

At 30 June 2013

Other comprehensive income/
(expenditure)

Transferred to issued capital

Share-based payments

At 30 June 2014

Other comprehensive income

Transferred to issued capital

Share-based payments

At 30 June 2015

Nature and purpose of reserves

Consolidation reserve

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.

(Accumulated Losses) / Retained earnings

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

Balance 1 July

Net (loss) / profit for the year

Balance at 30 June

Capital Management

Consolidated

2015
$’000

2014
$’000

45,728

23,778

(63,468)

21,950

(17,740)

45,728

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 2015 and 30 June 2014.

Notes to the Financial StatementFor the year ended 30 June 2015
21. Financial risk management objectives and policies

The Group’s principal financial instruments comprise cash and short term deposits, receivables, available for sale 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
taken 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.

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 2015:

Consolidated

Financial assets

Available for sale investments

Financial liabilities

Success fee financial liability

Carrying amount

Fair value

Level

2015
$’000

2014
$’000

2015
$’000

2014
$’000

1,343

26,040

1,343

26,040

3,066

4,004

3,066

4,004

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.

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 BMG assets acquired on 7 May 2014. Refer to Note 19 for details. The significant unobservable
valuation input 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; and discount rate of 2.98%.

Notes to the Financial StatementFor the year ended 30 June 2015
21. Financial risk management objectives and policies continued

Derivative financial instruments

The derivative financial instruments relate to options the Group has entered into to mitigate the risk on the Group’s operating cash flow of oil
price movements. At 30 June 2015, the fair value of these options is nil.

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 2015 and 30 June 2014.

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 2015 and 30 June 2014

• The impact on equity is the same as the impact on profit before tax

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, Euro’s and Polish Zloty’s. Transaction exposures, where possible, are netted off across the Group to reduce volatility and
provide a natural hedge.

The Group may from time to time have cash denominated in United States dollars, Euro’s and Polish Zloty’s.

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

2015
$’000

3,198

6,360

2014
$’000

5,269

1,618

4,531

1,265

2,897

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%

If the Australian dollar were higher at the balance date by 10%

If the Australian dollar were lower at the balance date by 10%

Impact on after
tax profit

(758)

926

(775)

947

Impact on other
comprehensive income

(99)

(15)

Notes to the Financial StatementFor the year ended 30 June 201521. Financial risk management objectives and policies continued

b) Commodity Price risk

The Group uses oil price options to manage some of its transaction exposures. These options are not 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 net of option contracts.

Commodity price risk arises from the sale of oil denominated in US dollars. The Group has provisional sales at 30 June 2015 of $5,009,182
(2014: $5,835,000).

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

2015
$’000

537

(537)

2014
$’000

593

(593)

c) Interest rate risk

The Group has no borrowings at 30 June 2015 (2014: $ 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 $31,993,000 (2014: $39,506,670).

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

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

Credit risk

Impact on after
tax profit

2015
$’000

(46)

2014
$’000

(39)

Credit risk arises from the financial assets of the Group which comprise cash and cash equivalents and trade and other 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 $8,936,000 (2014: $12,343,000) 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 BMG 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.

Notes to the Financial StatementFor the year ended 30 June 201521. Financial risk management objectives and policies continued

Share price risk

Share price risk arises from the movement of share prices on a prescribed stock exchange. The Group has available for sale investments the
fair value of which fluctuates as a result of movement in the share price.

Impact on available
for sale investment
reserve

Impact on profit
before tax

2015
$’000

2014
$’000

2015
$’000

2014
$’000

If the share price were 10% higher at the balance date

If the share price were 10% lower at the balance date

134

2,604

(134)

(2,604)

22. Commitments and contingencies

Operating lease commitments under non-cancellable office lease not provided for in the financial
statements and payable:

Within one year

After one year but not more than five years

After more than five years

Total minimum lease payments

Consolidated

2015
$’000

2014
$’000

357

582

939

277

778

1,055

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

44,597

12,359

11,742

19,228

56,956

30,970

As at 30 June 2015 the Parent entity has bank guarantees for $4,067,000 (2014: $4,520,000). 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 201523. 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

2015

2014

Oil and gas exploration

33.33%

Australia

PEL 186

VIC/L26

VIC/L27

VIC/L28

Indonesia

Sukananti KSO

Sumbagsel PSC

Merangin III PSC

Tunisia

Oil and gas exploration and production

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

Australia

PEL 90

PEL 93

PEL 100

PEL 110

PEL 494

PEL 495

PEP 150

PEP 168

PEP 171

PEP 151

PPL 207

PRL 32

PRL 85-104*
(Formerly PEL 92)

VIC/RL3

Oil and gas exploration

Oil and gas exploration and production

Oil and gas exploration

Oil and gas exploration and production

Orbost Gas Plant

Gas production

Tunisia

65%

55%

100%

30%

85%

65%

55%

100%

30%

85%

25%

30%

25%

30%

19.167%

20%

30%

20%

50%

25%

75%

30%

25%

50%

20%

30%

20%

50%

25%

75%

30%

25%

Hammamet Exploration Permit

Oil and gas exploration

35%

*Includes associated PPL’s

Notes to the Financial StatementFor the year ended 30 June 2015
24. Related parties

The Group has a related party relationship with its subsidiaries, joint arrangements (see note 23) and with its key management personnel
(refer to disclosure for key management personnel below).

Key management personnel disclosures

The following were key management personnel of the Group at any time during the reporting period and unless otherwise indicated were
key management personnel for the entire period.

Non-Executive Directors

Mr J. Conde AO (Chairman)

Mr J. W. Schneider

Ms A. Williams

Executives at year end

Executive Directors

Mr D. P. Maxwell

Mr H. M. Gordon

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

Ms A. Evans (Legal Counsel and Company Secretary)

Mr I. MacDougall (Operations Manager)

Mr A. Thomas (Exploration Manager)

Mr E. Glavas (Commercial and Business Development Manager – appointed 4 August 2014)

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

Short-term benefits

Long-term benefits

Post-employment benefits

Performance Rights

Total

Consolidated

2015
$

2014
$

3,983,833

3,149,451

160,281

123,832

1,129,020

799,626

5,723,134

4,072,909

Notes to the Financial StatementFor the year ended 30 June 2015

24. 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

Country of
incorporation

British Virgin Islands

Equity interest

2015
%

100%

2014
%

100%

Cooper Energy Sumbagsel Limited

British Virgin Islands

100%

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

British Virgin Islands

Australia

Netherlands

Poland

100%

99%

100%

99%

100%

During the reporting period, the Group provided geological and technical services to joint arrangements it manages at a cost of $2,822,000
(2014: $1,929,000). At the end of the financial period, $391,000 was outstanding for these services (2014: $1,004,000).

An impairment assessment is undertaken each financial year of related party receivables by examining the financial position of the related
party and their investment in the respective joint ventures which are prospecting for hydrocarbons to determine whether there is objective
evidence that a related party receivable is impaired. When such objective evidence exists, the Group recognises an allowance for the
impairment loss.

Notes to the Financial StatementFor the year ended 30 June 2015
25. Share based payment plans

On 16 December 2011 shareholders of Cooper Energy approved the establishment of an Employee Performance Rights Plan whereby the
Board can, subject to certain conditions, issue performance rights to employees to acquire shares in the parent entity.

During the financial year, issues were made on December 2014. The performance rights were issued for no consideration. The right extends
to the holder the right to be vested with shares in the parent entity.

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:

Number of
rights granted

Average share price
at commencement
date of grant (cents)

Average contractual
life of rights at
grant date in years

Remaining life of
rights in years

Date Granted

2 August 2012

10 December 2012

31 May 2013

6 November 2013

28 April 2014

1 December 2014

252,980

5,172,342

267,607

6,581,999

312,033

6,584,708

$0.437

$0.574

$0.471

$0.405

$0.510

$0.285

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

2015

2014

14,748,003

8,561,370

6,584,708

6,894,032

(2,669,814)

(135,588)

(223,478)

(1,162,444)

(571,811)

17,276,975

14,748,003

1,746,390

1,704,527

Notes to the Financial StatementFor the year ended 30 June 2015
25. Share based payment plans continued

The fair value of services received in return for the performance rights granted are measured by reference to the fair value of performance
rights granted. The estimate of the fair value of the services received is measured based on the Black-Scholes methodology to produce
a Monte-Carlo simulation model that allows for the incorporation of market based performance hurdles that must be met before the shares
vest to the holder.

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

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

2 August 2012

40.6 cents

48.5 cents

2.65%

42%

10 December 2012

45.8 cents

58.5 cents

2.64%

43%

31 May 2013

24.9 cents

38 cents

2.59%

44%

6 November 2013

31.2 cents

40.5 cents

2.82%

48%

28 April 2014

36.0 cents

51.0 cents

2.72%

49%

Notes to the Financial StatementFor the year ended 30 June 201525. Share based payment plans continued

Fair value assumptions

Fair value at measurement date

Share price

Risk free interest rate

Expected volatility

Dividend yield

26. Auditors remuneration

1 December 2014

19.4 cents

28.5 cents

2.35%

51%

Consolidated

2015
$

2014
$

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

183,120

201,220

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

27. Parent entity information

Information relating to Cooper Energy Limited

Current Assets

Total Assets

Current Liabilities

Total Liabilities

Issued capital

(Accumulated loss)/Retained profits

Option premium reserve

Realised and Unrealised (loss)/gain on available for sale financial assets

Share based payment reserve

Total shareholders’ equity

Profit/(loss) of the parent entity

Total comprehensive income/(loss) of the parent entity

183,120

201,220

183,120

201,220

Parent Entity

2015
$’000

2014
$’000

45,939

54,535

173,462

240,278

8,179

12,961

61,323

72,339

115,460

114,625

(9,119)

45,168

5,773

3,141

4,980

112,139

167,939

(54,287)

21,024

(3,260)

6,522

Notes to the Financial StatementFor the year ended 30 June 201527. Parent entity information continued

Commitments and Contingencies

Operating lease commitments under non-cancellable office lease not provided for in the financial
statements and payable:

Within one year

After one year but not more than five years

After more than five years

Total minimum lease payments

28. Events after the reporting period

Sales agreement for Sole Gas Project

Parent Entity

2015
$’000

2014
$’000

357

582

939

277

778

1,055

On 3 August 2015 the Group announced the signing of a Heads of Agreement with O-I Australia which defines the key terms for the sale
of gas from the Sole gas field. The key terms set out in the Heads of Agreement will form the basis of a fully termed gas sales agreement
which will be subject to an affirmative Final Investment Decision for development of the Sole gas field.

Consolidation of PEL 494 and PEL 495

The consolidation of PEL 494 and PEL 495, located in the Otway basin, was approved pursuant to the Petroleum and Geothermal Energy
Act 2000 on 6 August 2015 with an effective date of 20 March 2015. The consolidated area was designated as PEL 494 and the former
PEL 495 was consequently revoked.

BMG retention lease

The BMG Joint Venture currently holds life-of-field Production Licences VIC/L26, VIC/L27 & VIC/L28 over the BMG fields. Pursuant to
the Offshore Petroleum and Greenhouse Gas Storage Act 2006, the Joint Authority may terminate a production licence if no petroleum
recovery operations under the licence have been carried on at any time during a continuous period of at least 5 years. The Joint Venture
plans to submit applications to convert the existing licences to petroleum retention leases by 18 August 2015 in order to preserve tenure
over these blocks until petroleum recovery operations can again commence. The reversion to petroleum retention leases may have
consequences on Petroleum Resource Rent Tax as noted in note 5.

100

Notes to the Financial StatementFor the year ended 30 June 2015Directors’ 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 2015 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 2015.

Signed is accordance with a resolution of the Directors.

Mr John C. Conde AO
Chairman

17 August 2015

Mr David P. Maxwell
Director

101

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

102

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

103

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

104

Securities Exchange and Shareholder Information
as at 31 August 2015

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

Number of Shareholders
There were 5,050 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 2015)

Size of Shareholding

Number of holders

Number of Shares

% of issued capital

1 - 1,000

1,001 - 5,000

5,001 - 10,000

10,001 - 100,000

100,001 - 9,999,999,999

Total

Unquoted Options on Issue
Nil

Unquoted Performance Rights

1,088

1,415

830

1,539

178

5,050

308,527

4,132,232

6,886,242

51,239,486

269,519,389

332,085,876

0.09

1.24

2.07

15.43

81.16

100.00

Number of Holders of Performance Rights

Total Performance Rights

17,023,996

Unmarketable Parcels
There were 1,812 members, representing 1,625,444 shares, holding less than a marketable parcel of 2,778 shares in the company.

Twenty Largest Shareholders

Rank Name

10.

11.

12.

13.

14.

15.

16.

17.

18.

19.

20.

Beach Energy Limited

J P Morgan Nominees Australia Limited

HSBC Custody Nominees (Australia) Limited

National Nominees Limited

Zero Nominees Pty Ltd

Citicorp Nominees Pty Limited

Cairnglen Investments Pty Ltd

BNP Paribas Noms Pty Ltd

Navigator Australia Ltd

Kavel Pty Ltd

Bresrim Nominees Pty Ltd

Vanez Holdings Pty Ltd

Celtic Trust Company Ltd

Town Inns (Holdings) Pty Ltd

Mrs Tracy Michele Kleemann

Amalgamated Dairies Limited

CPU Share Plans Pty Limited

Chesser Nominees Pty Ltd

Jakana Pty Ltd

Units

% of Issued Capital

60,590,884

48,906,692

28,493,046

22,442,633

17,001,753

15,628,316

5,956,495

4,880,000

4,632,091

2,791,295

2,768,482

1,610,970

1,350,000

1,329,281

1,300,000

1,106,803

1,055,933

1,020,163

1,000,000

18.25

14.73

8.58

6.76

5.12

4.71

1.79

1.47

1.39

0.84

0.83

0.49

0.41

0.40

0.39

0.33

0.32

0.31

0.30

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

224,864,837

67.71

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

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

18.41%

7.15%

105

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.

106

Corporate Directory

Directors
John C Conde AO, Chairman

David P Maxwell

Hector M Gordon

Jeffery 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