TABLE OF CONTENTS
CHAIR’S LETTER ............................................................................................................................................................................1
CHIEF EXECUTIVE OFFICER’S LETTER ..............................................................................................................................2
OPERATING AND FINANCIAL REVIEW ............................................................................................................................. 3
DIRECTORS’ REPORT .............................................................................................................................................................. 27
EXECUTIVE SUMMARY – REMUNERATION ................................................................................................................... 33
REMUNERATION REPORT ..................................................................................................................................................... 34
AUDITOR’S INDEPENDENCE DECLARATION ...............................................................................................................49
FINANCIAL REPORT ................................................................................................................................................................ 50
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME ............................................................................ 51
CONSOLIDATED BALANCE SHEET................................................................................................................................... 52
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY ....................................................................................... 53
CONSOLIDATED STATEMENT OF CASH FLOWS ...................................................................................................... 54
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS ............................................................................... 55
DIRECTORS’ DECLARATION ................................................................................................................................................ 96
INDEPENDENT AUDITOR’S REPORT ................................................................................................................................ 97
ASX ADDITIONAL INFORMATION ................................................................................................................................... 102
CORPORATE GOVERNANCE STATEMENT ................................................................................................................. 103
INTERESTS IN PETROLEUM PERMITS AND PIPELINE LICENCES ..................................................................... 104
GLOSSARY AND ABBREVIATIONS ................................................................................................................................. 106
CORPORATE DIRECTORY ................................................................................................................................................... 107
__________________
Cover photo: View from Palm Valley 12 drilling site by Phil Allen
Forward-looking statements:
This document contains forward-looking statements, including (without limitation) statements of current intention, opinion, predictions and
expectations regarding Central’s present and future operations, possible future events and future financial prospects. Such statements are not
statements of fact, are not certain and are susceptible to change and may be affected by a variety of known and unknown risks, variables and changes
in underlying assumptions or strategy that could cause Central’s actual results or performance to differ materially from the results or performance
expressed or implied by such statements. There can be no certainty of outcome in relation to the matters to which the statements relate. Central
makes no representation, assurance or guarantee as to the accuracy or likelihood of fulfilment of any forward-looking statement (whether express or
implied) or any outcomes expressed or implied in any forward-looking statement. The forward-looking statements in this document reflect
expectations held at the date of this document. Except as required by applicable law or the Australian Securities Exchange (ASX) Listing Rules, Central
disclaims any obligation or undertaking to publicly update any forward-looking statements.
i
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
CHAIR’S LETTER
Dear Shareholders,
When we recently began our growth-oriented exploration
program, we knew that going down this path would not be
without risk. This is why the program was designed with
multiple wells targeting a variety of prospects.
So, while it is disappointing that we haven’t had the success we
had hoped for from our exploration program, there have also
been a number of positive developments in the last year which
bode well for the Company’s future. In particular, gas markets
have strengthened, providing opportunities for higher revenues
and margins from our existing producing fields, and we have
seen strong interest in the helium and hydrogen prospects of
our Amadeus Basin permits, stimulating investment in these
opportunities.
Not everyone was surprised by the turmoil that energy markets
experienced this winter. The headlong rush towards renewable
energy has exposed vulnerabilities in the market’s ability to
reliably meet demand for electricity. It was natural gas which
filled the gaps and kept the lights on, demonstrating the critical
role that gas will continue to play as the world transitions to a
lower-carbon future.
Central is well-placed to contribute to Australia’s energy security
in coming years. From May, Central and its partners were able to
supply gas into the critically short east coast markets through
newly secured transportation arrangements. These market
dynamics prompted us to re-assess our capital allocation
priorities, replacing the Dingo exploration well with high-value
projects which could increase near-term production capacity
from our existing fields.
That Central had this flexibility is a reflection of our diverse
portfolio and the steps taken to ensure availability of capital for
new projects.
Our exploration portfolio continues to attract international
interest and investment in its helium and hydrogen
prospectivity, driving the Company forward on a potential new
path for growth. The introduction of Peak Helium as a new
partner in three permits will be the catalyst for a substantial
new three well sub-salt exploration program, starting next year.
Success at any of the three leads could prove to be company-
changing, such is the prospective size of each target and the
flow-on potential for additional leads throughout the Amadeus
Basin.
Other opportunities for oil at Mamlambo and sub-salt
exploration at the Zevon lead are attracting interest from
potential partners and we hope to be able to add these to our
exploration program in the near future.
It has been a year of much activity, and we could not have
drilled the five wells without the support of our local
stakeholders – we thank the landowners and Traditional Owners
of the land on which we operate. We value these relationships
and continue to provide employment and business
opportunities locally while respecting and protecting the local
environment.
I thank my colleagues on the Board, our CEO, Leon Devaney and
all the staff at Central who have contributed to our resilience
and continue to work hard to build a stronger company.
Stuart Baker stepped down from the Board in August and I thank
him for his contribution since 2018. We also welcome Troy Harry
to the Board as a Director, bringing with him significant
experience in equity markets.
Our growth strategy remains in progress, and we have a number
of potentially value-accretive activities underway that could
deliver success in the near-term: production growth from the
Palm Valley 12 well and recompletions and new wells at
Mereenie; three sub-salt exploration wells in 2023/2024; testing
of the Range CSG pilot; and a possible Mamlambo exploration
well and seismic acquisition at Zevon.
We see our portfolio as being increasingly valuable in a
tightening gas market and with rising interest in helium and
hydrogen prospects. The Company’s value in the equity market
however doesn’t appear to reflect this optimism, and the Board
will engage an independent advisor to assist with a review of the
Company’s asset portfolio, capital structure and growth
opportunities.
While we conduct this review, we will continue to advance the
various programs that are in progress, and we look forward to
sharing the outcome of the review with our shareholders in the
coming year.
Thank you,
Mick McCormack, Chair
16 September 2022
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
1
CHIEF EXECUTIVE OFFICER’S LETTER
OPERATING AND FINANCIAL REVIEW
Dear Fellow Shareholders,
I’m pleased to present Central Petroleum’s FY2022 Annual
Report.
It has been a busy year which has seen Central make progress in
several key growth strategies, balanced by a disappointing initial
result from our exploration program.
A key catalyst for drilling activity this year was the completion of
the sale of 50% of our Amadeus Basin producing assets,
welcoming NZOG and Cue as new joint venture partners. The
asset sale crystallised part of the value we have created in our
operating assets, with a book profit of $36.6 million from assets
acquired only six years earlier. The acquisition of those operating
assets has been a great investment, with a return on equity after
debt service of over 33% per annum.
The asset sale allowed us to pay down $29 million of debt and
fund the Palm Valley 12 exploration / appraisal well, new and
recompleted wells at Mereenie and further production
enhancement at Mereenie next year.
The recompletions and new wells drilled at Mereenie in 2021
boosted aggregate Mereenie production to over 12 PJe for the
year and allowed Central and its partners to lock in a new four-
year gas sale agreement from 1 January 2022 at very attractive
prices.
The additional production capacity at Mereenie, combined with
new transport and spot trading arrangements from early May,
enabled us to deliver uncontracted non-firm gas into eastern
markets for the first time. This commercial milestone was well
timed, as the last quarter saw a near perfect storm in energy
markets with geopolitical issues, off-line coal fired generation and
colder weather resulting in historically high pricing for electricity,
gas and oil.
Over a three-month period to the end of July 2022 we supplied
over 85 TJ (Central share) of gas into eastern spot markets at an
average delivered price of $36/GJ, generating over $3 million in
revenue from our uncontracted non-firm production. The strong
spot market pricing has since eased, but this continuing access to
east coast spot pricing will provide ongoing margin support.
The Palm Valley 12 exploration well spud in April and has proved
to be one of the more difficult onshore drilling assignments faced
by Central due to the existence of highly fractured sub-strata that
required repeated and extensive plugging and cementing. Whilst
our decision to swap the original deep target for a shallower
target was appropriate given the cost and drilling circumstances,
the P2/P3 appraisal was ultimately not successful. As had always
been the strategy to create value, the PV12 well is now being
sidetracked into the existing production reservoir in the P1 for
completion as a production well. Nonetheless, the Palm Valley
exploration result was disappointing as we had hoped to find a
significant new volume of gas for sale into strong gas markets.
With the delays experienced at Palm Valley and the strong
market dynamics supporting additional near-term production, we
also made the tough decision to defer the planned Dingo well to
direct investment to increasing near-term production. Deferral of
deep exploration and pivoting to lower risk appraisal and
development gives us the best opportunity to quickly and
significantly increase near-term production.
With the deep in-field targets able to be explored at a later date,
we turn our attention to the farmout arrangement with Peak
Helium announced in February which is the catalyst for three
major new sub-salt exploration wells in the Amadeus Basin,
starting in 2023. These wells, including the much-anticipated
Dukas well, are seeking to unlock potentially large volumes of
natural gas, helium and naturally occurring hydrogen. This
commitment to sub-salt exploration drilling in 2023 reflects the
buoyant market for these gasses and demonstrates the
enormous potential of our sub-salt prospects.
There is also the potential to work with new partners to fund
additional exploration in our portfolio, including the Mamlambo
oil prospect, which could open up a new oil play on the western
flank of the Amadeus Basin, and the large Zevon sub-salt lead.
In Queensland, our Range CSG project continues to de-water,
albeit at rates slower than initially anticipated. In order to
increase our technical understanding of the permit, we drilled
two new wells during the year and are currently conducting an
extended three well production test. Gas flows are slowly
building, and we will evaluate the results later this year in
conjunction with a data swap covering neighbouring CSG permits.
Our producing assets continue to perform strongly. We booked
$42.2 million of revenues, $16.7 million of underlying EBITDAX
and a statutory profit of $21.3 million, inclusive of the $36.6
million profit on the partial asset sale which has also
strengthened the balance sheet. Cash at year end was a healthy
$21.6 million and net debt was reduced to $10.2 million. We also
extended our debt facility for a further three years, with lower
repayments, providing critical financial stability.
I thank our dedicated staff for their efforts in safely and
efficiently operating our producing fields and for managing three
separate drilling campaigns in challenging conditions. We
farewell our GM Exploration, Dr Duncan Lockhart . I thank
Duncan for his contribution to Central’s exploration efforts over
the past three years and wish him well in his future endeavours. I
also thank our many stakeholders for their continued support
throughout the year.
Although we didn’t have initial success from our PV12 exploration
well, it is important to keep this particular result in perspective.
There remains much to look forward to, including a three well
sub-salt campaign with enormous potential which will kick off
within 12 months; the Range pilot continues to provide critical
data; production enhancement programs are planned for
Mereenie; and we are continuing to explore opportunities to
progress new exploration at Mamlambo and Zevon.
Given the events over the past year, and subdued share price
within a high energy market, the Board has initiated a review of
our portfolio in order to ensure shareholders fully benefit from
the value we create from our assets and we look forward to
sharing this progress as it unfolds.
Leon Devaney, CEO
16 September 2022
On 1 October 2021, Central completed the sale of 50% of its interests in the Mereenie, Palm Valley and Dingo fields for consideration
valued at circa $85 million, recording a book profit of $36.6 million and facilitating the retirement of $30 million of debt.
OPERATING HIGHLIGHTS
Underlying EBITDAX of $16.7 million.
Full year statutory profit after tax of $21.3 million.
Reduced net debt by 67% to $10.2 million and extended the loan facility by three years to 30 September 2025.
The Mereenie development program was completed, with new production brought online.
Continued outperformance of the Palm Valley 13 well and Dingo gas field resulted in an increase of 3.5 PJe of 2P reserves as at
31 December 2021.
Entered into a new gas sale agreement for the sale of 3.15 PJ of gas over four years from 1 January 2022.
In early May 2022, Central entered into gas transport and spot trading arrangements allowing for the delivery of uncontracted gas into
the Eastern Australian markets. Through May and June sales into these markets achieved an average delivered price of $34/GJ.
Commenced drilling the Palm Valley 12 exploration well in April 2022. The sidetrack into the Lower P2/P3 Sandstones proved
unsuccessful in August, and a second lateral appraisal well is currently being drilled into the P1 Sandstone which is the current
production zone at Palm Valley.
Entered into a farmout of interests in the Group’s Amadeus Basin exploration tenements EP82, EP112 and EP125 with a three-well
exploration program to commence in 2023. The Group will be free-carried for its share of costs (capped at $20 million gross cost per
well) for two new sub-salt exploration wells targeting natural gas, helium and hydrogen.
•
•
•
•
•
•
•
•
•
•
Underlying EBITDAX: Decreased 36% to $16.7m in FY2022*
(Earnings before interest, tax, depreciation, impairment,
exploration costs, and profit on asset disposals)
Operating revenue: Decreased 30% to $42.1m in FY2022*
2P Reserves decreased due to disposals and production to 73.3 PJe
Net Debt: decreased by 67% to $10.2 million at 30 June 2022
* Note that Central disposed of 50% of its interests in its producing fields as at 1 October 2021, an effective 37.5% reduction in annual production capacity for FY2022
2
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
3
CHIEF EXECUTIVE OFFICER’S LETTER
OPERATING AND FINANCIAL REVIEW
OPERATING HIGHLIGHTS
On 1 October 2021, Central completed the sale of 50% of its interests in the Mereenie, Palm Valley and Dingo fields for consideration
valued at circa $85 million, recording a book profit of $36.6 million and facilitating the retirement of $30 million of debt.
•
Underlying EBITDAX of $16.7 million.
•
•
•
•
•
•
•
•
•
Full year statutory profit after tax of $21.3 million.
Reduced net debt by 67% to $10.2 million and extended the loan facility by three years to 30 September 2025.
The Mereenie development program was completed, with new production brought online.
Continued outperformance of the Palm Valley 13 well and Dingo gas field resulted in an increase of 3.5 PJe of 2P reserves as at
31 December 2021.
Entered into a new gas sale agreement for the sale of 3.15 PJ of gas over four years from 1 January 2022.
In early May 2022, Central entered into gas transport and spot trading arrangements allowing for the delivery of uncontracted gas into
the Eastern Australian markets. Through May and June sales into these markets achieved an average delivered price of $34/GJ.
Commenced drilling the Palm Valley 12 exploration well in April 2022. The sidetrack into the Lower P2/P3 Sandstones proved
unsuccessful in August, and a second lateral appraisal well is currently being drilled into the P1 Sandstone which is the current
production zone at Palm Valley.
Entered into a farmout of interests in the Group’s Amadeus Basin exploration tenements EP82, EP112 and EP125 with a three-well
exploration program to commence in 2023. The Group will be free-carried for its share of costs (capped at $20 million gross cost per
well) for two new sub-salt exploration wells targeting natural gas, helium and hydrogen.
EBITDAX (Underlying)
Operating revenue
n
o
i
l
l
i
M
$
30.0
25.0
20.0
15.0
10.0
5.0
-
n
o
i
l
l
i
M
$
70.0
60.0
50.0
40.0
30.0
20.0
10.0
-
Dear Fellow Shareholders,
Report.
I’m pleased to present Central Petroleum’s FY2022 Annual
With the deep in-field targets able to be explored at a later date,
It has been a busy year which has seen Central make progress in
several key growth strategies, balanced by a disappointing initial
result from our exploration program.
we turn our attention to the farmout arrangement with Peak
Helium announced in February which is the catalyst for three
major new sub-salt exploration wells in the Amadeus Basin,
starting in 2023. These wells, including the much-anticipated
Dukas well, are seeking to unlock potentially large volumes of
A key catalyst for drilling activity this year was the completion of
natural gas, helium and naturally occurring hydrogen. This
the sale of 50% of our Amadeus Basin producing assets,
commitment to sub-salt exploration drilling in 2023 reflects the
welcoming NZOG and Cue as new joint venture partners. The
buoyant market for these gasses and demonstrates the
asset sale crystallised part of the value we have created in our
enormous potential of our sub-salt prospects.
operating assets, with a book profit of $36.6 million from assets
acquired only six years earlier. The acquisition of those operating
assets has been a great investment, with a return on equity after
debt service of over 33% per annum.
The asset sale allowed us to pay down $29 million of debt and
fund the Palm Valley 12 exploration / appraisal well, new and
recompleted wells at Mereenie and further production
enhancement at Mereenie next year.
The recompletions and new wells drilled at Mereenie in 2021
boosted aggregate Mereenie production to over 12 PJe for the
year and allowed Central and its partners to lock in a new four-
year gas sale agreement from 1 January 2022 at very attractive
prices.
There is also the potential to work with new partners to fund
additional exploration in our portfolio, including the Mamlambo
oil prospect, which could open up a new oil play on the western
flank of the Amadeus Basin, and the large Zevon sub-salt lead.
In Queensland, our Range CSG project continues to de-water,
albeit at rates slower than initially anticipated. In order to
increase our technical understanding of the permit, we drilled
two new wells during the year and are currently conducting an
extended three well production test. Gas flows are slowly
building, and we will evaluate the results later this year in
conjunction with a data swap covering neighbouring CSG permits.
Our producing assets continue to perform strongly. We booked
$42.2 million of revenues, $16.7 million of underlying EBITDAX
The additional production capacity at Mereenie, combined with
and a statutory profit of $21.3 million, inclusive of the $36.6
new transport and spot trading arrangements from early May,
million profit on the partial asset sale which has also
enabled us to deliver uncontracted non-firm gas into eastern
strengthened the balance sheet. Cash at year end was a healthy
markets for the first time. This commercial milestone was well
$21.6 million and net debt was reduced to $10.2 million. We also
timed, as the last quarter saw a near perfect storm in energy
extended our debt facility for a further three years, with lower
markets with geopolitical issues, off-line coal fired generation and
repayments, providing critical financial stability.
colder weather resulting in historically high pricing for electricity,
gas and oil.
I thank our dedicated staff for their efforts in safely and
efficiently operating our producing fields and for managing three
Over a three-month period to the end of July 2022 we supplied
separate drilling campaigns in challenging conditions. We
over 85 TJ (Central share) of gas into eastern spot markets at an
farewell our GM Exploration, Dr Duncan Lockhart . I thank
average delivered price of $36/GJ, generating over $3 million in
Duncan for his contribution to Central’s exploration efforts over
revenue from our uncontracted non-firm production. The strong
the past three years and wish him well in his future endeavours. I
spot market pricing has since eased, but this continuing access to
also thank our many stakeholders for their continued support
east coast spot pricing will provide ongoing margin support.
throughout the year.
The Palm Valley 12 exploration well spud in April and has proved
Although we didn’t have initial success from our PV12 exploration
to be one of the more difficult onshore drilling assignments faced
well, it is important to keep this particular result in perspective.
by Central due to the existence of highly fractured sub-strata that
There remains much to look forward to, including a three well
required repeated and extensive plugging and cementing. Whilst
sub-salt campaign with enormous potential which will kick off
our decision to swap the original deep target for a shallower
within 12 months; the Range pilot continues to provide critical
target was appropriate given the cost and drilling circumstances,
data; production enhancement programs are planned for
the P2/P3 appraisal was ultimately not successful. As had always
Mereenie; and we are continuing to explore opportunities to
been the strategy to create value, the PV12 well is now being
progress new exploration at Mamlambo and Zevon.
sidetracked into the existing production reservoir in the P1 for
completion as a production well. Nonetheless, the Palm Valley
exploration result was disappointing as we had hoped to find a
significant new volume of gas for sale into strong gas markets.
Given the events over the past year, and subdued share price
within a high energy market, the Board has initiated a review of
our portfolio in order to ensure shareholders fully benefit from
the value we create from our assets and we look forward to
With the delays experienced at Palm Valley and the strong
sharing this progress as it unfolds.
market dynamics supporting additional near-term production, we
also made the tough decision to defer the planned Dingo well to
direct investment to increasing near-term production. Deferral of
deep exploration and pivoting to lower risk appraisal and
development gives us the best opportunity to quickly and
significantly increase near-term production.
Leon Devaney, CEO
16 September 2022
2018
2019
2020
2021
2022
FY2018
FY2019
FY2020
FY2021
FY2022
2P Reserves decreased due to disposals and production to 73.3 PJe
Net Debt: decreased by 67% to $10.2 million at 30 June 2022
* Note that Central disposed of 50% of its interests in its producing fields as at 1 October 2021, an effective 37.5% reduction in annual production capacity for FY2022
2
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
3
FY2018
FY2019
FY2020
FY2021
FY2022
FY2018
FY2019
FY2020
FY2021
FY2022
Operating revenue: Decreased 30% to $42.1m in FY2022*
Net debt
Underlying EBITDAX: Decreased 36% to $16.7m in FY2022*
(Earnings before interest, tax, depreciation, impairment,
exploration costs, and profit on asset disposals)
Reserves and resources
2P Reserves Contingent 2C Resources
450
400
350
300
250
200
150
100
50
0
n
o
i
l
l
i
M
$
70.0
60.0
50.0
40.0
30.0
20.0
10.0
-
t
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e
a
v
u
q
e
e
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a
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e
P
)
E
J
P
(
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OPERATING AND FINANCIAL REVIEW
FINANCIAL REVIEW
The Consolidated Entity had a profit after income tax for the year ended 30 June 2022 of $21.3 million (2021: $0.3 million).
The above result was after expensing exploration costs of $21.6 million (2021: $7.7 million). The Group’s policy is to expense all exploration
costs as incurred.
To assist with comparability of this year’s result, EBITDAX, EBITDA and EBIT have been reported against the underlying results in FY2021.
Note that a direct comparison of annual results will be impacted by:
1) The profit on sale of 50% of the Group’s interests in its producing properties which completed on 1 October 2021 (which is
excluded from the underlying results to assist with comparability); and
2) The decrease in revenues, production costs, capital expenditure and exploration costs resulting from the 50% reduction in the
Group’s equity interest in its producing assets from 1 October 2021.
The table below shows key metrics for the Group:
Key Metrics
Decrease in FY22 production capacity due to asset sale
Net Sales Volumes
-
-
Natural Gas (TJ)
Oil & Condensate (bbls)
Sales Revenue ($‘000)
Gross Profit ($‘000)
Underlying EBITDAX1 ($‘000)
Underlying EBITDA2 ($’000)
Underlying EBIT3 ($‘000)
Underlying (loss)/profit after tax4 ($’000)
Statutory profit after tax ($‘000)
Net cash inflow from Operations5 ($’000)
Capital expenditure6 ($‘000)
Total
2022
Total
2021
Change
% Change
5,993
47,197
42,151
20,894
16,746
(4,901)
(11,680)
(15,239)
21,320
3,640
10,053
9,820
77,255
59,827
30,975
26,088
18,349
5,846
251
251
24,136
11,792
(3,827)
(30,058)
(17,676)
(10,081)
(9,342)
(23,250)
(17,526)
(15,490)
21,069
(20,496)
(1,739)
(37.5)%
(39.0)%
(39.0)%
(30.0)%
(33.0)%
(36.0)%
(127.0)%
(300.0)%
N/a
N/a
(85.0)%
(15.0)%
Reconciliation of statutory profit before tax to underlying EBITDAX
Statutory profit before tax
Profit on disposal of 50% interest in Amadeus Basin producing properties
Underlying (loss)/profit before tax
Net finance costs and restatement of financial assets
Underlying EBIT
Depreciation and amortisation
Underlying EBITDA
Exploration expenses
Underlying EBITDAX
Sales Volumes
2022
$’000
21,320
(36,559)
(15,239)
3,559
(11,680)
6,779
(4,901)
21,647
16,746
2021
$’000
251
—
251
5,595
5,846
12,503
18,349
7,739
26,088
Sales volumes were 39% lower than FY2021 at 6.3 PJe, reflecting the Group’s reduced equity interests in the Amadeus Basin producing
properties from 1 October 2021.
1 Underlying EBITDAX is Earnings before Interest, Tax, Depreciation, Amortisation, Impairment and Exploration costs and profit on disposal of interests in producing
Note: Oil converted at 5.816 GJ/bbl.
properties (refer reconciliation below).
2 Underlying EBITDA is Earnings before Interest, Tax, Depreciation, Amortisation, Impairment and profit on disposal of interests in producing properties.
3 Underlying EBIT is Earnings before Interest, Tax and profit on disposal of interests in producing properties.
4 Underlying profit / loss after tax is statutory profit after tax, before profit on disposal of interests in producing properties.
5 Cashflow from Operations includes cash outflows associated with exploration activities. 2021 includes the proceeds from pre-sold gas.
6 Capital expenditure on tangible assets.
Underlying EBITDAX, underlying EBITDA and underlying EBIT are non-IFRS measures that are presented to provide an understanding of the
underlying performance of the Group. The non-IFRS information is not subject to audit review, however the numbers have been extracted
from the financial statements which have been subject to review by the Group’s auditor. A reconciliation to profit before tax is provided
below.
EBITDAX
Underlying EBITDAX for the year was $16.7 million, down 36% from $26.1 million in 2021 and consistent with the reduced earning base which
resulted from the disposal of 50% of the Group’s interests in the Amadeus Basin producing properties on 1 October 2021. Further discussion
on revenues and gross profit are included below.
Underlying EBITDAX are earnings before interest, tax depreciation, amortisation, impairment, exploration and profit on disposal of interests
in producing properties. Underlying EBITDAX is used by management as an indicative measure of underlying operating profit from operations
as it excludes non-cash items, the costs of finance and expensed exploration costs and is reconciled to statutory profit below.
It should be noted however that Underlying EBITDAX is only an indicative measure of underlying cash profit from operations. There are other
significant non-cash items included in underlying EBITDAX, such as share based payments amounting to $1.5 million this year (2021:
$1.9 million). Revenues recognised may also not reflect actual cash receipts, as some gas revenues relate to presold gas for which cash was
received in previous periods and amounts received under ‘take or pay’ gas contracts are not recognised as revenue until the gas is taken or
forfeited by the customer.
Central recorded sales revenue of $42.2 million, down 30% on FY2021, reflecting the lower volumes, partially offset by stronger global oil
prices and higher realised gas prices. Realised prices were up 15% on FY2021 at $6.73/GJe, reflecting higher global oil prices and domestic
gas sales into the higher-priced east coast spot market in May and June.
Gross profit was $20.9 million, increasing 10% from $3.02/GJe to $3.33/GJe on a per unit basis. The unit cost of sales increased by 21%,
reflecting fixed costs spread over lower volumes and includes additional transportation costs for spot sales in May and June.
Sales Revenue
Gross Profit
Other Income
A $36.6 million profit was recognised on disposal of 50% of the Group’s interests in the Amadeus Basin producing properties which
completed on 1 October 2021. Proceeds included $29.6 million of cash, deferred consideration in the form of a carry of the Group’s share
of future exploration and development costs with a fair value of $29.8 million and the assumption of liabilities associated with the disposed
assets with a carrying value of $40.9 million at the time of completion.
Non-cash depreciation and amortisation costs decreased from $12.5 million to $6.8 million, reflecting the decrease in asset base following
Depreciation and Amortisation
the 50% disposal transaction.
Net Assets/Liabilities
At 30 June 2022, the Group had a net asset position of $26.5 million, a significant improvement on FY2021 due to the net profit for the year
before share based payments, including the $36.6 million gain from the partial sale of the Amadeus Basin producing properties.
4
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
5
OPERATING AND FINANCIAL REVIEW
FINANCIAL REVIEW
costs as incurred.
To assist with comparability of this year’s result, EBITDAX, EBITDA and EBIT have been reported against the underlying results in FY2021.
Note that a direct comparison of annual results will be impacted by:
1) The profit on sale of 50% of the Group’s interests in its producing properties which completed on 1 October 2021 (which is
excluded from the underlying results to assist with comparability); and
2) The decrease in revenues, production costs, capital expenditure and exploration costs resulting from the 50% reduction in the
Group’s equity interest in its producing assets from 1 October 2021.
The table below shows key metrics for the Group:
Key Metrics
Decrease in FY22 production capacity due to asset sale
Net Sales Volumes
Natural Gas (TJ)
-
-
Oil & Condensate (bbls)
Sales Revenue ($‘000)
Gross Profit ($‘000)
Underlying EBITDAX1 ($‘000)
Underlying EBITDA2 ($’000)
Underlying EBIT3 ($‘000)
Underlying (loss)/profit after tax4 ($’000)
Statutory profit after tax ($‘000)
Net cash inflow from Operations5 ($’000)
Capital expenditure6 ($‘000)
Total
2022
Total
2021
Change
% Change
5,993
47,197
42,151
20,894
16,746
(4,901)
(11,680)
(15,239)
21,320
3,640
10,053
9,820
77,255
59,827
30,975
26,088
18,349
5,846
251
251
24,136
11,792
(3,827)
(30,058)
(17,676)
(10,081)
(9,342)
(23,250)
(17,526)
(15,490)
21,069
(20,496)
(1,739)
(37.5)%
(39.0)%
(39.0)%
(30.0)%
(33.0)%
(36.0)%
(127.0)%
(300.0)%
N/a
N/a
(85.0)%
(15.0)%
1 Underlying EBITDAX is Earnings before Interest, Tax, Depreciation, Amortisation, Impairment and Exploration costs and profit on disposal of interests in producing
properties (refer reconciliation below).
2 Underlying EBITDA is Earnings before Interest, Tax, Depreciation, Amortisation, Impairment and profit on disposal of interests in producing properties.
3 Underlying EBIT is Earnings before Interest, Tax and profit on disposal of interests in producing properties.
4 Underlying profit / loss after tax is statutory profit after tax, before profit on disposal of interests in producing properties.
5 Cashflow from Operations includes cash outflows associated with exploration activities. 2021 includes the proceeds from pre-sold gas.
6 Capital expenditure on tangible assets.
Underlying EBITDAX, underlying EBITDA and underlying EBIT are non-IFRS measures that are presented to provide an understanding of the
underlying performance of the Group. The non-IFRS information is not subject to audit review, however the numbers have been extracted
from the financial statements which have been subject to review by the Group’s auditor. A reconciliation to profit before tax is provided
below.
EBITDAX
Underlying EBITDAX for the year was $16.7 million, down 36% from $26.1 million in 2021 and consistent with the reduced earning base which
resulted from the disposal of 50% of the Group’s interests in the Amadeus Basin producing properties on 1 October 2021. Further discussion
on revenues and gross profit are included below.
Underlying EBITDAX are earnings before interest, tax depreciation, amortisation, impairment, exploration and profit on disposal of interests
in producing properties. Underlying EBITDAX is used by management as an indicative measure of underlying operating profit from operations
as it excludes non-cash items, the costs of finance and expensed exploration costs and is reconciled to statutory profit below.
It should be noted however that Underlying EBITDAX is only an indicative measure of underlying cash profit from operations. There are other
significant non-cash items included in underlying EBITDAX, such as share based payments amounting to $1.5 million this year (2021:
$1.9 million). Revenues recognised may also not reflect actual cash receipts, as some gas revenues relate to presold gas for which cash was
received in previous periods and amounts received under ‘take or pay’ gas contracts are not recognised as revenue until the gas is taken or
forfeited by the customer.
4
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
The Consolidated Entity had a profit after income tax for the year ended 30 June 2022 of $21.3 million (2021: $0.3 million).
Reconciliation of statutory profit before tax to underlying EBITDAX
Statutory profit before tax
The above result was after expensing exploration costs of $21.6 million (2021: $7.7 million). The Group’s policy is to expense all exploration
Profit on disposal of 50% interest in Amadeus Basin producing properties
Underlying (loss)/profit before tax
Net finance costs and restatement of financial assets
Underlying EBIT
Depreciation and amortisation
Underlying EBITDA
Exploration expenses
Underlying EBITDAX
Sales Volumes
2022
$’000
21,320
(36,559)
(15,239)
3,559
(11,680)
6,779
(4,901)
21,647
16,746
2021
$’000
251
—
251
5,595
5,846
12,503
18,349
7,739
26,088
Sales volumes were 39% lower than FY2021 at 6.3 PJe, reflecting the Group’s reduced equity interests in the Amadeus Basin producing
properties from 1 October 2021.
Sales volumes
14.0
12.0
10.0
)
E
J
P
(
t
i
l
n
e
a
v
u
q
e
e
u
o
a
e
P
t
j
l
8.0
6.0
4.0
2.0
-
Purchased Gas
Mereenie overlift
Produced
FY2018
FY2019
FY2020
FY2021
FY2022
Note: Oil converted at 5.816 GJ/bbl.
Sales Revenue
Central recorded sales revenue of $42.2 million, down 30% on FY2021, reflecting the lower volumes, partially offset by stronger global oil
prices and higher realised gas prices. Realised prices were up 15% on FY2021 at $6.73/GJe, reflecting higher global oil prices and domestic
gas sales into the higher-priced east coast spot market in May and June.
Gross Profit
Gross profit was $20.9 million, increasing 10% from $3.02/GJe to $3.33/GJe on a per unit basis. The unit cost of sales increased by 21%,
reflecting fixed costs spread over lower volumes and includes additional transportation costs for spot sales in May and June.
Other Income
A $36.6 million profit was recognised on disposal of 50% of the Group’s interests in the Amadeus Basin producing properties which
completed on 1 October 2021. Proceeds included $29.6 million of cash, deferred consideration in the form of a carry of the Group’s share
of future exploration and development costs with a fair value of $29.8 million and the assumption of liabilities associated with the disposed
assets with a carrying value of $40.9 million at the time of completion.
Depreciation and Amortisation
Non-cash depreciation and amortisation costs decreased from $12.5 million to $6.8 million, reflecting the decrease in asset base following
the 50% disposal transaction.
Net Assets/Liabilities
At 30 June 2022, the Group had a net asset position of $26.5 million, a significant improvement on FY2021 due to the net profit for the year
before share based payments, including the $36.6 million gain from the partial sale of the Amadeus Basin producing properties.
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
5
OPERATING AND FINANCIAL REVIEW
Included in liabilities on the Group’s balance sheet are amounts recognised in respect of deferred revenue associated with pre-sales and
make-up gas provisions amounting to $18.9 million. These liabilities will be transferred to revenue as gas is supplied to the customer or
forfeited to Central under take-or-pay contracts and therefore do not represent a cash liability to the Group. During the year, 0.75 PJ of
previously over-lifted gas was repaid to a joint venture partner and 1.1 PJ of pre-sold gas was delivered.
Debt
The Group repaid $36.0 million of loan principal during the year including a $29 million repayment from the proceeds of the partial sale of
the Amadeus Basin producing properties. The outstanding balance of the loan facility at 30 June 2022 was $30.8 million with $4.5 million
due for repayment in FY2023.
During the year, the term of the loan facility was extended by three years to 30 September 2025.
Net debt reduced by 67% to $10.2 million at 30 June 2022 reflecting loan repayments from the proceeds of the partial asset sale.
The consolidated debt ratio at 30 June 2022 improved to 0.26 (2021: 0.39). Debt ratio is defined as: Total Debt/Total Assets. Net gearing at
30 June 2022 was 11% (2021: 27% or 28% if re-based to 30 June 2022 market capitalisation). Net gearing is calculated as: Net Debt /
(Market capitalisation + Net Debt). Debt service is supported by long term gas sales contracts and the Group’s certified oil and gas reserves.
Net Cash Flow
Cash balances decreased by $15.5 million over the year. Net cash flow from production operations for 2022 was $19.8 million compared to
$37.7 million for 2021, with the decrease reflecting the reduced interests in the Amadeus Basin producing properties from 1 October 2021
and the proceeds from the presale of gas in FY2021.
After payment of $2.5 million of interest costs, $3.7 million of corporate expenses and $10.1 million for exploration activities, net cash flow
from operating activities was $3.6 million, down from $24.1 million in 2021. Exploration expenditure in FY2022 was $4.7 million higher than
FY2021, reflecting additional activity this year on the Amadeus exploration program and Range pilot program.
During the year, Central invested $10.8 million in capital projects, including new production wells at Mereenie and other sustaining capital
expenditure at the three producing fields.
A further $7.6 million of Central’s share of exploration costs and $2.0 million of development costs were paid (“carried”) by joint venturers
under the terms of the partial asset sale.
Central repaid $36 million of debt during the year including a $29 million lump sum repayment from the proceeds of the partial asset sale.
Five Year Comparative Data
The following table is a five-year comparative analysis of the Consolidated Entity’s key financial information. The balance sheet information
is as at 30 June each year and all other data is for the years then ended.
Financial Data
Operating revenue
Exploration expenditure
Profit/(loss) after income tax
EBITDAX
Underlying EBITDAX
Equity issued during year
Property, plant and equipment1
Cash1
Borrowings
Net Assets (Total Equity)
Net Working Capital (Net current assets/(liabilities))
1 Includes assets classified as held for sale
2018
$ MILLION
2019
$ MILLION
2020
$ MILLION
2021
$ MILLION
2022
$ MILLION
34.94
8.79
(14.08)
11.01
11.01
25.47
103.85
27.22
(78.33)
7.06
17.19
59.36
15.80
(14.53)
22.19
22.19
.—
123.48
17.81
(81.73)
(5.62)
(1.53)
65.05
5.28
5.41
33.40
25.01
.—
107.85
25.92
(70.77)
1.58
6.75
59.83
7.74
0.25
26.09
26.09
.—
108.28
37.17
(66.81)
3.69
8.25
42.15
21.65
21.32
53.31
16.75
—
53.85
21.65
(30.81)
26.53
22.31
Operating Data
Gas Sales (TJ)
Oil Sales (barrels)
No. of employees at 30 June
2018
2019
2020
2021
2022
4,842
105,619
89
10,229
97,392
99
11,822
89,016
92
9,820
77,255
85
5,993
47,197
88
OPERATIONS AND ACTIVITIES
Central Petroleum Limited is an ASX-listed oil and gas producer, with a portfolio of producing and prospective tenements across the
Northern Territory (NT) and Queensland. Central is the operator of the largest onshore gas producing fields in the NT, supplying industrial
customers, electricity generators and senior gas distributors from three producing fields near Alice Springs.
Producing Assets
Location of Central’s producing oil and gas fields
Sales Volumes (Central Petroleum’s Share)
Product
Gas
Total
Crude and Condensate
Unit
FY 2022 FY 2021
PJ
bbls
PJe
6.0
9.8
47,197
77,255
6.3
10.3
Note: Oil is converted to Petajoule equivalent (PJe) at 5.816 GJe/bbl.
Central’s sales volumes were 39% lower than FY2021 at 6.3 PJe, reflecting reduced ownership interests following the sale of 50% of
Central’s interest in the Mereenie, Palm Valley and Dingo fields on 1 October 2021. On a full field basis, sales volumes increased slightly, up
1% as increased production from new wells at Mereenie and higher demand for Dingo gas offset natural decline at Palm Valley.
Central’s sales volume
6
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
7
Included in liabilities on the Group’s balance sheet are amounts recognised in respect of deferred revenue associated with pre-sales and
make-up gas provisions amounting to $18.9 million. These liabilities will be transferred to revenue as gas is supplied to the customer or
forfeited to Central under take-or-pay contracts and therefore do not represent a cash liability to the Group. During the year, 0.75 PJ of
previously over-lifted gas was repaid to a joint venture partner and 1.1 PJ of pre-sold gas was delivered.
OPERATIONS AND ACTIVITIES
Central Petroleum Limited is an ASX-listed oil and gas producer, with a portfolio of producing and prospective tenements across the
Northern Territory (NT) and Queensland. Central is the operator of the largest onshore gas producing fields in the NT, supplying industrial
customers, electricity generators and senior gas distributors from three producing fields near Alice Springs.
The Group repaid $36.0 million of loan principal during the year including a $29 million repayment from the proceeds of the partial sale of
the Amadeus Basin producing properties. The outstanding balance of the loan facility at 30 June 2022 was $30.8 million with $4.5 million
Producing Assets
" Town
Railway
Gas Pipeline
Oil Pipeline
Gas Field
Oil Field
Central Production Licence
Central Granted Permits
Central Permit Applications
Surprise
Oil Field
L6
A M A D E U S B A S I N
Mereenie Spur Gas
Pipeline (116 km)
Mereenie Oil
and Gas
Field
OL4
OL5
¯ 0
50
100
km
Location of Central’s producing oil and gas fields
A m adeus - D arwin G as
Pipeline (1 51 2 k m)
Palm Valley
Gas Field
OL3
Mereenie Oil Pipeline
(269 km)
Alice Springs Gas Pipeline
(145 km)
ALICE SPRINGS
ALICE SPRINGS
ALICE SPRINGS
"
Dingo Gas Field
L7
A further $7.6 million of Central’s share of exploration costs and $2.0 million of development costs were paid (“carried”) by joint venturers
Sales Volumes (Central Petroleum’s Share)
Product
Unit
FY 2022 FY 2021
Gas
Crude and Condensate
Total
PJ
bbls
PJe
6.0
47,197
9.8
77,255
6.3
10.3
Note: Oil is converted to Petajoule equivalent (PJe) at 5.816 GJe/bbl.
Central’s sales volumes were 39% lower than FY2021 at 6.3 PJe, reflecting reduced ownership interests following the sale of 50% of
Central’s interest in the Mereenie, Palm Valley and Dingo fields on 1 October 2021. On a full field basis, sales volumes increased slightly, up
1% as increased production from new wells at Mereenie and higher demand for Dingo gas offset natural decline at Palm Valley.
Sales volumes by field (100% JV full field)
20,000
18,000
16,000
14,000
)
e
J
T
(
OPERATING AND FINANCIAL REVIEW
Debt
due for repayment in FY2023.
During the year, the term of the loan facility was extended by three years to 30 September 2025.
Net debt reduced by 67% to $10.2 million at 30 June 2022 reflecting loan repayments from the proceeds of the partial asset sale.
The consolidated debt ratio at 30 June 2022 improved to 0.26 (2021: 0.39). Debt ratio is defined as: Total Debt/Total Assets. Net gearing at
30 June 2022 was 11% (2021: 27% or 28% if re-based to 30 June 2022 market capitalisation). Net gearing is calculated as: Net Debt /
(Market capitalisation + Net Debt). Debt service is supported by long term gas sales contracts and the Group’s certified oil and gas reserves.
Net Cash Flow
Cash balances decreased by $15.5 million over the year. Net cash flow from production operations for 2022 was $19.8 million compared to
$37.7 million for 2021, with the decrease reflecting the reduced interests in the Amadeus Basin producing properties from 1 October 2021
and the proceeds from the presale of gas in FY2021.
After payment of $2.5 million of interest costs, $3.7 million of corporate expenses and $10.1 million for exploration activities, net cash flow
from operating activities was $3.6 million, down from $24.1 million in 2021. Exploration expenditure in FY2022 was $4.7 million higher than
FY2021, reflecting additional activity this year on the Amadeus exploration program and Range pilot program.
During the year, Central invested $10.8 million in capital projects, including new production wells at Mereenie and other sustaining capital
expenditure at the three producing fields.
under the terms of the partial asset sale.
Five Year Comparative Data
Central repaid $36 million of debt during the year including a $29 million lump sum repayment from the proceeds of the partial asset sale.
The following table is a five-year comparative analysis of the Consolidated Entity’s key financial information. The balance sheet information
is as at 30 June each year and all other data is for the years then ended.
Financial Data
Operating revenue
Exploration expenditure
Profit/(loss) after income tax
EBITDAX
Underlying EBITDAX
Equity issued during year
Property, plant and equipment1
Cash1
Borrowings
Net Assets (Total Equity)
Operating Data
Gas Sales (TJ)
Oil Sales (barrels)
No. of employees at 30 June
Net Working Capital (Net current assets/(liabilities))
1 Includes assets classified as held for sale
2018
2019
2020
2021
2022
$ MILLION
$ MILLION
$ MILLION
$ MILLION
$ MILLION
34.94
8.79
(14.08)
11.01
11.01
25.47
103.85
27.22
(78.33)
7.06
17.19
59.36
15.80
(14.53)
22.19
22.19
.—
123.48
17.81
(81.73)
(5.62)
(1.53)
65.05
5.28
5.41
33.40
25.01
.—
107.85
25.92
(70.77)
1.58
6.75
59.83
7.74
0.25
26.09
26.09
.—
108.28
37.17
(66.81)
3.69
8.25
42.15
21.65
21.32
53.31
16.75
—
53.85
21.65
(30.81)
26.53
22.31
2018
2019
2020
2021
2022
4,842
105,619
89
10,229
97,392
99
11,822
89,016
92
9,820
77,255
85
5,993
47,197
88
12,000
10,000
8,000
6,000
4,000
2,000
-
FY2018
FY2019
FY2020
FY2021
FY2022
Central’s sales volume
Central’s sales volume
Dingo
Palm Valley
Mereenie oil
Mereenie gas
t
n
e
a
v
u
q
e
e
u
o
a
r
r
e
T
l
j
l
i
6
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
7
OPERATING AND FINANCIAL REVIEW
Mereenie Oil and Gas Field (OL4 and OL5)
Northern Territory
Ownership interests
Central Petroleum (operator)
Macquarie Mereenie Pty Ltd
NZOG Mereenie Pty Ltd
Cue Mereenie Pty Ltd
25.0%
50.0%
17.5%
7.5%
Reserves & Resources
(Central share)1
Gas
Oil
Total2
Unit
1P
2P
2C
PJ
mmbbl
30.5
0.37
39.2
0.41
45.6
0.05
PJe
32.6
41.6
45.9
1 Reserves and resources are as at 30 June 2022. 2C gas resources
include 27 PJ attributable to the Stairway Sandstone.
2 Oil converted at 5.816 PJ/mmbbl
l
t
n
e
a
v
u
q
e
i
l
j
e
u
o
a
r
e
T
Mereenie sales volumes (100%)
14,000
12,000
10,000
8,000
6,000
4,000
2,000
-
FY2018
FY2019
FY2020
FY2021
FY2022
Mereenie gas Mereenie Oil
Palm Valley Gas Field (OL3)
Northern Territory
Ownership interests
Central Petroleum (operator)
NZOG Palm Valley Pty Ltd
Cue Palm Valley Pty Ltd
50.0%
35.0%
15.0%
Reserves & Resources
(Central share)1
Gas
Unit
PJ
1P
2P
11.3
12.7
2C
6.8
1 Reserves and resources are as at 30 June 2022.
Operations
Production from the Palm Valley field has continued to exceed expectations as a result of the ongoing outperformance of the PV13
production well. The field averaged gas sales of 6.5 TJ/d through FY2022, recording an aggregate of 2.4 PJ, down from 3.2 PJ in FY2021. The
PV13 well is declining from its peak production plateau experienced in FY2020 but continues to outperform initial expectations. Central’s
share of Palm Valley gas sales was 1.5 PJ, with a reduced ownership interest of 50% applying from 1 October 2021 when the partial asset
sale completed (previously 100%).
No new development wells were planned for FY2022 as additional production is expected from the PV12 exploration/appraisal well which,
having been unsuccessful at its exploration target is being side-tracked as a lateral appraisal/production well in the producing P1 Pacoota
Sandstone. Drilling progressed through the last quarter of the year after the well spud in April 2022. If successful in the Pacoota Sandstone,
PV12 could be quickly tied-in to the existing Palm Valley processing infrastructure.
Other potential locations have been identified for new lateral wells similar to the successful PV13 well in order to offset the field’s natural
decline, with timing of any future development to be determined by the outcome of the current PV12 appraisal well.
The deeper Arumbera Sandstone has potential as a significant gas resource and remains an exploration target at Palm Valley. The
Arumbera Sandstone is the production reservoir at the Dingo gas field, 100km to the east.
Geology
Gas at Palm Valley is primarily reservoired in an extensive fracture system in the lower Stairway and Pacoota Sandstones. The anticlinal
structure is approximately 29 km in length and 14 km in width. The deeper Arumbera Sandstone, which is the production interval at the
Dingo field some 100 km to the east, has yet to be appraised and remains an exploration target.
Operations
Full field gas production for the year was 11.6 PJ, averaging 31.7 TJ/d, up from the 10.7 PJ (29.5 TJ/d) produced in FY2021, benefitting from
the commissioning of new production wells which were commissioned in the first quarter. Oil production averaged 410 bbl/d, down
slightly from the 423 bbl/d produced in the previous year, as the new wells were crestally-located to target the gas cap, rather than the oil
rim. Central’s share of this Mereenie gas and oil production was 3.9 PJe, with a reduced ownership interest of 25% applying from 1 October
2021 when the partial asset sale completed (previously 50%).
Sustained gas flows were recorded from the Stairway Sandstone interval while drilling the WM28 production well, increasing the potential
for additional reserves to be added with future appraisal.
Future plans
In May 2022, Central entered into gas transport and spot trading arrangements allowing for the delivery of uncontracted gas into the
eastern Australian markets for the first time. Through May and June 2022, in addition to supplying its contracted customers in the
Northern Territory, Central supplied 61 TJ of gas from Mereenie into high-priced spot markets to support east coast gas users.
Mereenie oil and gas field central processing plant
Future plans
To further increase production and offset natural field decline in the next 12 months, it is planned to recomplete up to six existing wells to
access producing zones which were previously behind pipe. Planning has also commenced on two new development wells at Mereenie.
The overlying Stairway Sandstone formation could contain up to 108 PJ of gas (27 PJ Central share), making it an ideal candidate for future
appraisal.
Geology
The Mereenie hydrocarbon accumulation is contained in an elongated 4-way dip anticline that has a length of 40 km and width of
more than 5 km. The reservoirs comprise a series of stacked sandstones of the Pacoota Formation, which have been the focus of
development to date. This development has targeted both gas production and oil production from an oil rim. The overlying Stairway
Sandstone has not been materially developed to date, but it represents significant upside potential as the Stairway Formation has
produced gas in several wells.
Drilling at Palm Valley 12
by Phil Allen
8
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
9
j
l
s
e
u
o
a
r
e
T
Palm Valley Gas Field (OL3)
Northern Territory
Ownership interests
Central Petroleum (operator)
NZOG Palm Valley Pty Ltd
Cue Palm Valley Pty Ltd
50.0%
35.0%
15.0%
Reserves & Resources
(Central share)1
Gas
Unit
1P
2P
PJ
11.3
12.7
2C
6.8
1 Reserves and resources are as at 30 June 2022.
Palm Valley sales volumes (100%)
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
-
FY2018
FY2019
FY2020
FY2021
FY2022
Palm Valley Gas
OPERATING AND FINANCIAL REVIEW
Mereenie Oil and Gas Field (OL4 and OL5)
Northern Territory
Ownership interests
Central Petroleum (operator)
Macquarie Mereenie Pty Ltd
NZOG Mereenie Pty Ltd
Cue Mereenie Pty Ltd
25.0%
50.0%
17.5%
7.5%
Reserves & Resources
(Central share)1
Unit
1P
2P
2C
Gas
Oil
Total2
PJ
mmbbl
30.5
0.37
39.2
0.41
45.6
0.05
PJe
32.6
41.6
45.9
1 Reserves and resources are as at 30 June 2022. 2C gas resources
include 27 PJ attributable to the Stairway Sandstone.
2 Oil converted at 5.816 PJ/mmbbl
Operations
Full field gas production for the year was 11.6 PJ, averaging 31.7 TJ/d, up from the 10.7 PJ (29.5 TJ/d) produced in FY2021, benefitting from
the commissioning of new production wells which were commissioned in the first quarter. Oil production averaged 410 bbl/d, down
slightly from the 423 bbl/d produced in the previous year, as the new wells were crestally-located to target the gas cap, rather than the oil
rim. Central’s share of this Mereenie gas and oil production was 3.9 PJe, with a reduced ownership interest of 25% applying from 1 October
2021 when the partial asset sale completed (previously 50%).
Sustained gas flows were recorded from the Stairway Sandstone interval while drilling the WM28 production well, increasing the potential
for additional reserves to be added with future appraisal.
In May 2022, Central entered into gas transport and spot trading arrangements allowing for the delivery of uncontracted gas into the
eastern Australian markets for the first time. Through May and June 2022, in addition to supplying its contracted customers in the
Northern Territory, Central supplied 61 TJ of gas from Mereenie into high-priced spot markets to support east coast gas users.
Mereenie oil and gas field central processing plant
Future plans
appraisal.
Geology
To further increase production and offset natural field decline in the next 12 months, it is planned to recomplete up to six existing wells to
access producing zones which were previously behind pipe. Planning has also commenced on two new development wells at Mereenie.
The overlying Stairway Sandstone formation could contain up to 108 PJ of gas (27 PJ Central share), making it an ideal candidate for future
The Mereenie hydrocarbon accumulation is contained in an elongated 4-way dip anticline that has a length of 40 km and width of
more than 5 km. The reservoirs comprise a series of stacked sandstones of the Pacoota Formation, which have been the focus of
development to date. This development has targeted both gas production and oil production from an oil rim. The overlying Stairway
Sandstone has not been materially developed to date, but it represents significant upside potential as the Stairway Formation has
produced gas in several wells.
Operations
Production from the Palm Valley field has continued to exceed expectations as a result of the ongoing outperformance of the PV13
production well. The field averaged gas sales of 6.5 TJ/d through FY2022, recording an aggregate of 2.4 PJ, down from 3.2 PJ in FY2021. The
PV13 well is declining from its peak production plateau experienced in FY2020 but continues to outperform initial expectations. Central’s
share of Palm Valley gas sales was 1.5 PJ, with a reduced ownership interest of 50% applying from 1 October 2021 when the partial asset
sale completed (previously 100%).
No new development wells were planned for FY2022 as additional production is expected from the PV12 exploration/appraisal well which,
having been unsuccessful at its exploration target is being side-tracked as a lateral appraisal/production well in the producing P1 Pacoota
Sandstone. Drilling progressed through the last quarter of the year after the well spud in April 2022. If successful in the Pacoota Sandstone,
PV12 could be quickly tied-in to the existing Palm Valley processing infrastructure.
Future plans
Other potential locations have been identified for new lateral wells similar to the successful PV13 well in order to offset the field’s natural
decline, with timing of any future development to be determined by the outcome of the current PV12 appraisal well.
The deeper Arumbera Sandstone has potential as a significant gas resource and remains an exploration target at Palm Valley. The
Arumbera Sandstone is the production reservoir at the Dingo gas field, 100km to the east.
Geology
Gas at Palm Valley is primarily reservoired in an extensive fracture system in the lower Stairway and Pacoota Sandstones. The anticlinal
structure is approximately 29 km in length and 14 km in width. The deeper Arumbera Sandstone, which is the production interval at the
Dingo field some 100 km to the east, has yet to be appraised and remains an exploration target.
8
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
9
Drilling at Palm Valley 12
by Phil Allen
Appraisal Assets – Surat Basin
Range Gas Project (ATP 2031)
Surat Basin, Queensland
(Central - 50% Interest, Incitec Pivot Queensland Gas Ltd (IPL) - 50%)
Reserves & Resources
(Central share)
Gas
Unit
PJ
1P
—
2P
—
2C
135
similar depths.
Range pilot operations
Interference testing of the original Range pilot confirmed good
communication between the three pilot wells. However, key
water production targets were not met during the testing period.
Two new step-out wells (Range 9 and 10) were drilled in
February 2022 to assess coal properties and water production
rates at a distance of approximately 2km from the initial pilot
location. The two new wells confirmed net coal of 29.8m and
28.6m respectively, compared to the average 25.5m of coal
encountered at the site of the initial three well pilot. Despite
being less than 2km from the original pilot, these results are
more comparable to the average 32.9m of coal encountered in
previous exploration wells. The new pilot step-out wells were
tied into the existing water tank and an extended production test
commenced in early April.
One of the original pilot wells, Range-6 was returned to
production and testing of the three wells continues. Gas flows
have been gradually increasing and the pilot wells are currently
producing at an aggregate rate of 40,000 scfd.
Location of the Range Gas Project (ATP 2031) wells in relation to coal depth
The new wells are intended to provide key information to support appraisal of the permit, including reservoir productivity (initially via
water rates), gas desorption (when gas is first produced), zonal contribution (how much each coal seam is contributing) and the initial
production profiles of gas and water ramp-up. This information will be reviewed in conjunction with data obtained from neighbouring
permits.
OPERATING AND FINANCIAL REVIEW
Dingo Gas Field (L7) and Dingo Pipeline (PL30)
Northern Territory
Ownership interests
Central Petroleum (operator)
NZOG Dingo Pty Ltd
Cue Dingo Pty Ltd
50.0%
35.0%
15.0%
Reserves & Resources
(Central share)1
Gas
Unit
1P
2P
PJ
16.2
19.0
2C
—
1 Reserves and resources are as at 30 June 2022.
l
s
e
u
o
a
r
e
T
j
Dingo sales volumes (100%)
1,600
1,400
1,200
1,000
800
600
400
200
-
FY2018
FY2019
FY2020
FY2021
FY2022
Dingo Gas
Central and joint venture partner, Incitec Pivot Limited are progressing appraisal for the 77km2 Range coal seam gas (CSG) project which is
strategically located in the heart of Queensland’s CSG province which hosts thousands of wells producing from the same coal measures at
Instrumentation at Brewer Estate City Gate Station
Operations
The Dingo Gas Field supplies gas through a dedicated 50 km gas pipeline to Brewer Estate in Alice Springs for use in the Owen Springs
Power Station.
Sales volumes averaged 3.7 TJ/d across the year, an aggregate of 1.4 PJ, up 10% on FY2021 due to increased demand from the power station.
The daily contract volume of 4.4 TJ/d is subject to take-or-pay provisions under which Central will be paid in January 2023 for any gas
nomination shortfall by the customer in CY2022. Central’s share of gas sales was 0.9 PJ, with a reduced ownership interest of 50% applying
from 1 October 2021 when the partial asset sale completed (previously 100%).
Future plans
Additional development wells can be drilled in the future at Dingo to maintain contracted gas volumes when warranted by natural field
decline.
The deeper Pioneer Sandstone, which has flowed gas at the nearby Ooraminna prospect, and the Areyonga Formation lie below the existing
production reservoir and could hold significant gas resources. A deep exploration well, previously scheduled for 2022, has been deferred to
prioritise capital for production enhancement at Mereenie.
Geology
Gas was discovered at the Dingo field in 1985 in the Neoproterozoic lower Arumbera Sandstone. The structure is 11 km by 5.6 km, and
the productive reservoir is at a depth of approximately 3,000 metres subsurface.
10
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
11
Range-9 drilling site
OPERATING AND FINANCIAL REVIEW
Dingo Gas Field (L7) and Dingo Pipeline (PL30)
Northern Territory
Ownership interests
Central Petroleum (operator)
NZOG Dingo Pty Ltd
Cue Dingo Pty Ltd
50.0%
35.0%
15.0%
Reserves & Resources
(Central share)1
Unit
1P
2P
Gas
PJ
16.2
19.0
2C
—
1 Reserves and resources are as at 30 June 2022.
Instrumentation at Brewer Estate City Gate Station
The Dingo Gas Field supplies gas through a dedicated 50 km gas pipeline to Brewer Estate in Alice Springs for use in the Owen Springs
Sales volumes averaged 3.7 TJ/d across the year, an aggregate of 1.4 PJ, up 10% on FY2021 due to increased demand from the power station.
The daily contract volume of 4.4 TJ/d is subject to take-or-pay provisions under which Central will be paid in January 2023 for any gas
nomination shortfall by the customer in CY2022. Central’s share of gas sales was 0.9 PJ, with a reduced ownership interest of 50% applying
from 1 October 2021 when the partial asset sale completed (previously 100%).
Additional development wells can be drilled in the future at Dingo to maintain contracted gas volumes when warranted by natural field
The deeper Pioneer Sandstone, which has flowed gas at the nearby Ooraminna prospect, and the Areyonga Formation lie below the existing
production reservoir and could hold significant gas resources. A deep exploration well, previously scheduled for 2022, has been deferred to
prioritise capital for production enhancement at Mereenie.
Operations
Power Station.
Future plans
decline.
Geology
Gas was discovered at the Dingo field in 1985 in the Neoproterozoic lower Arumbera Sandstone. The structure is 11 km by 5.6 km, and
the productive reservoir is at a depth of approximately 3,000 metres subsurface.
Appraisal Assets – Surat Basin
Range Gas Project (ATP 2031)
Surat Basin, Queensland
(Central - 50% Interest, Incitec Pivot Queensland Gas Ltd (IPL) - 50%)
Reserves & Resources
(Central share)
Gas
Unit
PJ
1P
—
2P
—
2C
135
Central and joint venture partner, Incitec Pivot Limited are progressing appraisal for the 77km2 Range coal seam gas (CSG) project which is
strategically located in the heart of Queensland’s CSG province which hosts thousands of wells producing from the same coal measures at
similar depths.
Range pilot operations
Interference testing of the original Range pilot confirmed good
communication between the three pilot wells. However, key
water production targets were not met during the testing period.
Two new step-out wells (Range 9 and 10) were drilled in
February 2022 to assess coal properties and water production
rates at a distance of approximately 2km from the initial pilot
location. The two new wells confirmed net coal of 29.8m and
28.6m respectively, compared to the average 25.5m of coal
encountered at the site of the initial three well pilot. Despite
being less than 2km from the original pilot, these results are
more comparable to the average 32.9m of coal encountered in
previous exploration wells. The new pilot step-out wells were
tied into the existing water tank and an extended production test
commenced in early April.
One of the original pilot wells, Range-6 was returned to
production and testing of the three wells continues. Gas flows
have been gradually increasing and the pilot wells are currently
producing at an aggregate rate of 40,000 scfd.
Range pilot wells
Range exploration wells
Gas pipeline
Walloon Fairway
Range Gas Project
Top Walloon Depth (mMD)
0
960
Range Gas Project
Range Gas Project
Range Gas Project
Range Gas Project
Range Gas Project
Range Gas Project
Range Gas Project
Range Gas Project
Range Gas Project
Range Gas Project
Range Gas Project
Range 5
Range 2
Other Permits
Range 10
Range 6
Range 3
Range 9
Range 4
¯
0
2.5
5
10
km
Location of the Range Gas Project (ATP 2031) wells in relation to coal depth
The new wells are intended to provide key information to support appraisal of the permit, including reservoir productivity (initially via
water rates), gas desorption (when gas is first produced), zonal contribution (how much each coal seam is contributing) and the initial
production profiles of gas and water ramp-up. This information will be reviewed in conjunction with data obtained from neighbouring
permits.
10
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
11
Range-9 drilling site
Drilling commenced on the PV12 exploration well on 17 April, with the primary target being the Arumbera Sandstone at an anticipated
Amadeus exploration – 2022 drilling activity
Palm Valley
(OL3) Amadeus Basin, Northern Territory
(Central – 50% interest)
vertical depth of 3,560m (PV Deep).
Gas shows were recorded whilst drilling through both the currently
productive P1 Sandstone and the P2/P3 Sandstones located 90m
below the P1.
Drilling progress was significantly slower that prognosed due to the
vertical well encountering a number of heavily fractured intervals that
absorbed significant volumes of drilling fluids and cement. Several
cement plugs were set to enable the setting of casing to ensure well
integrity. Having reached a depth of 2,335m, the joint venturers
decided on 12 July to replace the original PV Deep target with the
lower P2/P3 target at a depth of approximately 2,060m.
The vertical well was plugged back and the PV12 ST1 lateral well was
drilled into the P2/P3 Sandstones. Although the vertical PV12 well
intersected a major fracture zone within the lower P2 Sandstone and
background gas was detected while drilling horizontally, gas flows
were not detected from the lateral well and formation water was
encountered.
The P2/P3 lateral well was plugged back and a second lateral well
(PV12 ST2) side-tracked to test the shallower Pacoota (P1) Sandstone
(approx. 1,770m depth), which is the current producing zone for the
Palm Valley gas field. The PV12 ST2 lateral appraisal well is currently
drilling into the Pacoota Sandstones. The lateral design is similar to
the successful PV13 appraisal well drilled in 2019, which had a lateral
extension of 300m and has already produced approximately 5.7 PJs in
its first three years of production (gross JV).
Preparations are underway to connect the PV12 ST2 lateral well (if
successful) into the Palm Valley production infrastructure.
OPERATING AND FINANCIAL REVIEW
Exploration Assets
Central Petroleum holds a significant portfolio of exploration opportunities across the Northern Territory and Queensland, including
extensive positions in the long producing, yet underexplored Amadeus Basin in the NT, and frontier opportunities in the Wiso and Southern
Georgina basins. The total area held by Central for exploration (both granted and under application) is 181,743 km2 (72,197 km2 granted
and 109,545 km2 under application).
"
Town
Gas pipeline
W I S O
B A S I N
Proposed gas pipeline
Oil pipeline
Railway
Central Production Licence
Central Granted Permits
Central Permit Applications
"
TENNANT
TENNANT
TENNANT
CREEK
CREEK
CREEK
MOUNT ISA
MOUNT ISA
MOUNT ISA
MOUNT ISA
"
G E O R G I N A
B A S I N
Surprise
Oil Field
Mereenie Oil and
Gas Field
L6L6L6
EP115
OL4OL4OL4OL4OL4
OL5OL5OL5OL5OL5OL5OL5OL5OL5OL5OL5OL5OL5OL5OL5OL5OL5OL5
OL3OL3OL3OL3OL3OL3OL3OL3OL3OL3OL3OL3OL3OL3OL3OL3OL3OL3
Palm Valley
Gas Field
ALICE SPRINGS
ALICE SPRINGS
ALICE SPRINGS
ALICE SPRINGS
ALICE SPRINGS
"
3
L
R
4
L
R
L7L7L7L7L7L7L7L7L7L7L7L7L7L7L7L7L7L7L7L7L7
Dingo Gas Field
A M A D E U S
B A S I N
EP112
EP125
EP82
EP105
P E D I R K A
B A S I N
NORTHERN TERRITORY
SOUTH AUSTRALIA
¯ 0
50
100
200
km
A
I
L
A
R
T
S
U
A
N
R
E
T
S
E
W
ATP
912
ATP909
ATP
911
D
N
A
L
S
N
E
E
U
Q
Location of Central’s Petroleum Permits, Licences and Applications in Central Australia
Amadeus Basin
Central Petroleum has significant operations within the proven Amadeus Basin, which has some of Australia’s largest prospective onshore
resources of conventional gas. The Amadeus Basin has provided reliable, high-quality oil and gas since the 1980s, yet it is relatively under-
explored and it is believed to hold significant additional gas resources, with good prospectivity for oil on the western flank of the basin.
The Amadeus Basin is also prospective for helium and hydrogen. Previous exploration wells at Mt Kitty and Magee have shown high
concentrations of helium and hydrogen and are attracting increasing international attention. A new joint venture partner, Peak Helium, will
join Central and Santos to drill three exploration wells in 2023/2024, funding Central’s share of costs for two of the three new wells
(capped at $20 million total gross cost per well). These high-value non-hydrocarbon gases are generally associated with granitic basement
and sub-salt prospects and the three well program will be a key driver for Central in progressing other sub-salt exploration in the basin.
Over 100 potential oil and gas targets have been identified within Central’s Amadeus Basin footprint. Several high priority targets which
can be drilled conventionally and without stimulation (hydraulic fracturing) have been identified, including:
In-field opportunities: There are opportunities to target other intervals at Mereenie, Palm Valley and Dingo which are not currently
the principal production zones in each field. If successful, production wells could be tied into existing production facilities relatively
quickly and efficiently;
Near term opportunities: Oil and gas opportunities are located close to existing producing fields from intervals which have been
known to produce oil or gas from nearby wells; and
Large sub-salt targets with helium and hydrogen potential: The Amadeus Basin contains several large, potentially multi-Tcf sub-salt
targets that are also prospective for Helium and Hydrogen. Drilling is planned in 2023.
•
•
•
Amadeus exploration – In-field opportunities
Palm Valley (OL3); Dingo (L7); Mereenie (OL4/OL5), Amadeus Basin, Northern Territory
Schematic of the Palm Valley 12 exploration well
Central’s producing fields at Mereenie, Palm Valley and Dingo are comprised of several vertical layers of producing and potential oil and
gas reservoirs. There are opportunities to target other intervals which are not currently the principal production zones in each field. If
successful, production wells could be tied into existing production facilities relatively quickly and efficiently.
The deeper targets at Palm Valley and Dingo remain to be explored at a later date, as capital for the planned 2022 deep exploration wells
was redirected to a shallower target at Palm Valley and higher-priority production enhancement projects.
Palm Valley Deep (OL3)
Central - 50% interest (operator)
The Palm Valley Deep target has an estimated mean prospective resource of 123 PJ (61.5 PJ net to Central) in the deep Arumbera
Sandstone (depth circa 3,500m) which is the productive interval at the Dingo field. A new gas resource of this size at Palm Valley would be
a catalyst for a significant expansion of field production capacity and economic field life (current 2P gas reserves are 13 PJ net to Central).
12
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
13
OPERATING AND FINANCIAL REVIEW
Exploration Assets
Central Petroleum holds a significant portfolio of exploration opportunities across the Northern Territory and Queensland, including
extensive positions in the long producing, yet underexplored Amadeus Basin in the NT, and frontier opportunities in the Wiso and Southern
Georgina basins. The total area held by Central for exploration (both granted and under application) is 181,743 km2 (72,197 km2 granted
and 109,545 km2 under application).
Amadeus exploration – 2022 drilling activity
Palm Valley
(OL3) Amadeus Basin, Northern Territory
(Central – 50% interest)
Drilling commenced on the PV12 exploration well on 17 April, with the primary target being the Arumbera Sandstone at an anticipated
vertical depth of 3,560m (PV Deep).
Gas shows were recorded whilst drilling through both the currently
productive P1 Sandstone and the P2/P3 Sandstones located 90m
below the P1.
Drilling progress was significantly slower that prognosed due to the
vertical well encountering a number of heavily fractured intervals that
absorbed significant volumes of drilling fluids and cement. Several
cement plugs were set to enable the setting of casing to ensure well
integrity. Having reached a depth of 2,335m, the joint venturers
decided on 12 July to replace the original PV Deep target with the
lower P2/P3 target at a depth of approximately 2,060m.
The vertical well was plugged back and the PV12 ST1 lateral well was
drilled into the P2/P3 Sandstones. Although the vertical PV12 well
intersected a major fracture zone within the lower P2 Sandstone and
background gas was detected while drilling horizontally, gas flows
were not detected from the lateral well and formation water was
encountered.
The P2/P3 lateral well was plugged back and a second lateral well
(PV12 ST2) side-tracked to test the shallower Pacoota (P1) Sandstone
(approx. 1,770m depth), which is the current producing zone for the
Palm Valley gas field. The PV12 ST2 lateral appraisal well is currently
drilling into the Pacoota Sandstones. The lateral design is similar to
the successful PV13 appraisal well drilled in 2019, which had a lateral
extension of 300m and has already produced approximately 5.7 PJs in
its first three years of production (gross JV).
Palm Valley 12
Gas
1770m
P1
Pacoota
Sandstone
P1
P2
P3
Deep
Target
Arumbera
Sandstone
Preparations are underway to connect the PV12 ST2 lateral well (if
successful) into the Palm Valley production infrastructure.
Drawing not to scale.
Schematic of the Palm Valley 12 exploration well
Amadeus exploration – In-field opportunities
Palm Valley (OL3); Dingo (L7); Mereenie (OL4/OL5), Amadeus Basin, Northern Territory
Central’s producing fields at Mereenie, Palm Valley and Dingo are comprised of several vertical layers of producing and potential oil and
gas reservoirs. There are opportunities to target other intervals which are not currently the principal production zones in each field. If
successful, production wells could be tied into existing production facilities relatively quickly and efficiently.
The deeper targets at Palm Valley and Dingo remain to be explored at a later date, as capital for the planned 2022 deep exploration wells
was redirected to a shallower target at Palm Valley and higher-priority production enhancement projects.
Palm Valley Deep (OL3)
Central - 50% interest (operator)
The Palm Valley Deep target has an estimated mean prospective resource of 123 PJ (61.5 PJ net to Central) in the deep Arumbera
Sandstone (depth circa 3,500m) which is the productive interval at the Dingo field. A new gas resource of this size at Palm Valley would be
a catalyst for a significant expansion of field production capacity and economic field life (current 2P gas reserves are 13 PJ net to Central).
Location of Central’s Petroleum Permits, Licences and Applications in Central Australia
Amadeus Basin
Central Petroleum has significant operations within the proven Amadeus Basin, which has some of Australia’s largest prospective onshore
resources of conventional gas. The Amadeus Basin has provided reliable, high-quality oil and gas since the 1980s, yet it is relatively under-
explored and it is believed to hold significant additional gas resources, with good prospectivity for oil on the western flank of the basin.
The Amadeus Basin is also prospective for helium and hydrogen. Previous exploration wells at Mt Kitty and Magee have shown high
concentrations of helium and hydrogen and are attracting increasing international attention. A new joint venture partner, Peak Helium, will
join Central and Santos to drill three exploration wells in 2023/2024, funding Central’s share of costs for two of the three new wells
(capped at $20 million total gross cost per well). These high-value non-hydrocarbon gases are generally associated with granitic basement
and sub-salt prospects and the three well program will be a key driver for Central in progressing other sub-salt exploration in the basin.
Over 100 potential oil and gas targets have been identified within Central’s Amadeus Basin footprint. Several high priority targets which
can be drilled conventionally and without stimulation (hydraulic fracturing) have been identified, including:
In-field opportunities: There are opportunities to target other intervals at Mereenie, Palm Valley and Dingo which are not currently
the principal production zones in each field. If successful, production wells could be tied into existing production facilities relatively
quickly and efficiently;
Near term opportunities: Oil and gas opportunities are located close to existing producing fields from intervals which have been
known to produce oil or gas from nearby wells; and
Large sub-salt targets with helium and hydrogen potential: The Amadeus Basin contains several large, potentially multi-Tcf sub-salt
targets that are also prospective for Helium and Hydrogen. Drilling is planned in 2023.
•
•
•
12
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
13
OPERATING AND FINANCIAL REVIEW
Dingo Deep (L7)
Central - 50% interest (operator)
The Dingo Deep target has an estimated mean prospective resource of 69 PJ (34.5 PJ net to Central) in the deeper Pioneer Sandstone and
Areyonga Formation at a depth of up to 3,700m. Both formations have had gas shows with flows to surface achieved from the Pioneer
Sandstones at the Ooraminna well. A successful exploration test would open up a new play fairway in the basin and could prompt the
construction of new processing and pipeline infrastructure from the Dingo field which currently has 19 PJ of 2P gas reserves (net to
Central).
Mereenie Stairway (OL4/OL5)
Central - 25% interest (operator)
The Stairway Sandstones which overlie the deeper producing Pacoota Sandstones at Mereenie are estimated to contain 108 PJ of 2C
contingent gas resource (27 PJ net to Central). While drilling the WM28 production well in 2021, gas flowed from the Upper Stairway
Sandstone at 600,000 scfd, providing a good indication of the presence of open natural fractures in the crestal region of the Mereenie field.
If successful, production from the Stairway would significantly increase production capacity and the economic life of the Mereenie field
which currently has 2P gas reserves of 39 PJ (net to Central).
Near-term opportunities
Town
"
Railway
Gas Pipeline
Oil Pipeline
Central Production Licence
Dingo Satellite Area
Central Granted Permits
Central Permit Applications
G E O R G I N A B A S I N
Mamlambo
L6L6L6
Mereenie Stairway
OL3OL3OL3OL3OL3OL3OL3
Palm Valley Deep
EP82 DSA
EP82 DSA
EP82 DSA
ALICE
ALICE
SPRINGS
SPRINGS
SPRINGS
"
A M A D E U S B A S I N
Orange-3
Dingo Deep
L7L7L7L7L7L7L7L7L7L7L7L7L7L7L7L7L7
Orange (EP82(DSA))
Central - 100% interest
existing Dingo pipeline.
Lead / Prospect
Dingo Deep
Palm Valley Deep
Mereenie Stairway
Orange
Total gas resource
Mamlambo (oil)
Previous exploration wells at Orange have encountered gas at the shallow Arumbera Sandstone which is the producing zone at the Dingo
field, some 23km to the south-east. A future exploration well at Orange would target a mean prospective gas resource of 401 PJ from the
Arumbera Sandstone and the deeper Pioneer Sandstone and Areyonga Formation which are volumetrically significant and close to the
Prospective Resource1
Contingent
resource
Unit
PJ
PJ
PJ
PJ
PJ
mmbbl
Best
estimate
(P50)
24.5
37.5
—
284.0
346.0
13.0
Mean
34.5
61.5
—
401.0
497.0
18.0
2C
—
—
27.0
—
27.0
—
1. Prospective Resource: As first reported to ASX on 7 August 2020 for Dingo, Palm Valley and Orange, and 10 February 2022 for Mamlambo. The
volumes of prospective resources represent the unrisked recoverable volumes derived from Monte Carlo probabilistic volumetric analysis for each
prospect. Inputs required for these analyses have been derived from offset wells and fields relevant to each play and field. Recovery factors used
have been derived from analogous field production data.
Cautionary statement: 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 recoverable hydrocarbons.
Central confirms that it is not aware of any new information or data that materially affects the information included in those announcements and all
material assumptions and technical parameters underpinning the estimate continue to apply and have not materially changed.
Amadeus exploration – Sub-salt targets with helium and hydrogen potential
Amadeus Basin, Northern Territory
The Amadeus Basin hosts sub-salt targets within the Heavitree Formation and the fractured granitic basement sealed by extensive
evaporitic units of the upper Gillen Formation. In addition to hydrocarbons, the presence of radiogenic basement rocks and an evaporitic
sealing unit has created the ideal conditions for a helium and hydrogen play in the sub-salt section of the Amadeus Basin.
A
I
L
A
R
T
S
U
A
N
R
E
T
S
E
W
¯ 0
NORTHERN TERRITORY
SOUTH AUSTRALIA
100
200
km
P E D I R K A
B A S I N
Location map of immediate in-field and near-term exploration opportunities
Amadeus exploration – Near-term opportunities
Amadeus Basin, Northern Territory
Central has identified several other promising lower-risk, high reward exploration targets close to productive areas which it intends to
pursue in the near term. The targets include:
Mamlambo (L6)
Central - 100% interest
With an estimated mean prospective resource of 18 mmbbl of oil, Mamlambo is a large structure defined on an existing seismic grid, only
8km from the suspended Surprise oil field. An exploration well could target the Lower Stairway Sandstone and the Pacoota Formation,
both of which are proven reservoirs in the Surprise and Mereenie oil and gas fields. Total depth for a potential exploration well could be in
the order of 1,300m.
What is sub salt?
•
•
•
•
The term “sub-salt” is commonly applied
to the geology below deposits of salt
(evaporites).
Salt can form a very effective trap for not
only hydrocarbons, but very light gasses
like helium and hydrogen that typically
escape to the atmosphere.
Some of the largest oil and gas fields
discovered are sub-salt, in numerous
regions such as USA Gulf of Mexico,
offshore Brazil and offshore West Africa.
The Amadeus Basin has a unique
combination of basin-wide salt
formations extending over large areas
with opportunities for hydrocarbons, plus
helium and hydrogen produced by
radiolysis at basement.
14
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
15
OPERATING AND FINANCIAL REVIEW
Dingo Deep (L7)
Central - 50% interest (operator)
Central).
Mereenie Stairway (OL4/OL5)
Central - 25% interest (operator)
The Stairway Sandstones which overlie the deeper producing Pacoota Sandstones at Mereenie are estimated to contain 108 PJ of 2C
contingent gas resource (27 PJ net to Central). While drilling the WM28 production well in 2021, gas flowed from the Upper Stairway
Sandstone at 600,000 scfd, providing a good indication of the presence of open natural fractures in the crestal region of the Mereenie field.
If successful, production from the Stairway would significantly increase production capacity and the economic life of the Mereenie field
which currently has 2P gas reserves of 39 PJ (net to Central).
Location map of immediate in-field and near-term exploration opportunities
Amadeus exploration – Near-term opportunities
Amadeus Basin, Northern Territory
pursue in the near term. The targets include:
Mamlambo (L6)
Central - 100% interest
Central has identified several other promising lower-risk, high reward exploration targets close to productive areas which it intends to
With an estimated mean prospective resource of 18 mmbbl of oil, Mamlambo is a large structure defined on an existing seismic grid, only
8km from the suspended Surprise oil field. An exploration well could target the Lower Stairway Sandstone and the Pacoota Formation,
both of which are proven reservoirs in the Surprise and Mereenie oil and gas fields. Total depth for a potential exploration well could be in
the order of 1,300m.
The Dingo Deep target has an estimated mean prospective resource of 69 PJ (34.5 PJ net to Central) in the deeper Pioneer Sandstone and
Areyonga Formation at a depth of up to 3,700m. Both formations have had gas shows with flows to surface achieved from the Pioneer
Sandstones at the Ooraminna well. A successful exploration test would open up a new play fairway in the basin and could prompt the
construction of new processing and pipeline infrastructure from the Dingo field which currently has 19 PJ of 2P gas reserves (net to
Previous exploration wells at Orange have encountered gas at the shallow Arumbera Sandstone which is the producing zone at the Dingo
field, some 23km to the south-east. A future exploration well at Orange would target a mean prospective gas resource of 401 PJ from the
Arumbera Sandstone and the deeper Pioneer Sandstone and Areyonga Formation which are volumetrically significant and close to the
existing Dingo pipeline.
Orange (EP82(DSA))
Central - 100% interest
Lead / Prospect
Dingo Deep
Palm Valley Deep
Mereenie Stairway
Orange
Total gas resource
Mamlambo (oil)
Prospective Resource1
Contingent
resource
Unit
PJ
PJ
PJ
PJ
PJ
mmbbl
Best
estimate
(P50)
24.5
37.5
—
284.0
346.0
13.0
Mean
34.5
61.5
—
401.0
497.0
18.0
2C
—
—
27.0
—
27.0
—
1. Prospective Resource: As first reported to ASX on 7 August 2020 for Dingo, Palm Valley and Orange, and 10 February 2022 for Mamlambo. The
volumes of prospective resources represent the unrisked recoverable volumes derived from Monte Carlo probabilistic volumetric analysis for each
prospect. Inputs required for these analyses have been derived from offset wells and fields relevant to each play and field. Recovery factors used
have been derived from analogous field production data.
Cautionary statement: 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 recoverable hydrocarbons.
Central confirms that it is not aware of any new information or data that materially affects the information included in those announcements and all
material assumptions and technical parameters underpinning the estimate continue to apply and have not materially changed.
Amadeus exploration – Sub-salt targets with helium and hydrogen potential
Amadeus Basin, Northern Territory
The Amadeus Basin hosts sub-salt targets within the Heavitree Formation and the fractured granitic basement sealed by extensive
evaporitic units of the upper Gillen Formation. In addition to hydrocarbons, the presence of radiogenic basement rocks and an evaporitic
sealing unit has created the ideal conditions for a helium and hydrogen play in the sub-salt section of the Amadeus Basin.
What is sub salt?
•
•
•
•
The term “sub-salt” is commonly applied
to the geology below deposits of salt
(evaporites).
Salt can form a very effective trap for not
only hydrocarbons, but very light gasses
like helium and hydrogen that typically
escape to the atmosphere.
Some of the largest oil and gas fields
discovered are sub-salt, in numerous
regions such as USA Gulf of Mexico,
offshore Brazil and offshore West Africa.
The Amadeus Basin has a unique
combination of basin-wide salt
formations extending over large areas
with opportunities for hydrocarbons, plus
helium and hydrogen produced by
radiolysis at basement.
Well
I mp e r v i o u s
S e a l
Fractured reservoirs below impervious
salt seal can trap natural gas, plus lighter
high-value gases like He and H that
usually escape to atmosphere
2
S a l t
2
H + He produced by
radiolysis in basement
hydrocarbon
source
S a l t
Heavitree Fm
F r a c t u r e d
G r a n i t i c B a s e m e n t
Migration of
hydrocarbons
into fractured
basement
14
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
15
OPERATING AND FINANCIAL REVIEW
Farmout stimulates major sub-salt exploration program
In February, Central entered into a farmout of interests in three Amadeus Basin exploration tenements to Peak Helium (Amadeus Basin)
Pty Ltd (Peak). Under the farmout, Central will be free carried (i.e. funded) by Peak for two new sub-salt exploration wells (capped at
$20 million gross cost per well), one at Mt Kitty (EP 125) and the other at the Mahler prospect (EP 82).
Zevon West
Zevon East
Palm Valley
Gas Field
"
ALICE SPRINGS
ALICE SPRINGS
ALICE SPRINGS
ALICE SPRINGS
A M A D E U S
B A S I N
The Zevon sub-salt lead in EP115 has been defined as a potentially very large closure (circa 1,600 km2) from seismic and gravity studies. It is
located in the north-western section of the Amadeus Basin between the Mereenie oil & gas field and the Surprise oil field.
Regional geological play mapping has highlighted that this area has the potential to be highly prospective for helium and hydrogen in
Mereenie Oil
and Gas Field
Dukas
EP112
Dukas 1
Mount Kitty
Mt Kitty 1
EP125
NORTHERN TERRITORY
SOUTH AUSTRALIA
Dingo Gas Field
Magee
Magee 1
EP82
Mahler
EP134
Peak Helium
¯ 0
50
100
km
P E D I R K A
B A S I N
"
Town
Railway
Gas Field
Oil Field
Gas Pipeline
Oil Pipeline
Existing wells
Heavitree gas leads
Peak Helium permit
Central Production Licence
Farmout blocks
Central permits and
applications
Location of sub-salt targets
Combined with the planned Dukas exploration well, a total of three sub-salt exploration wells will now be prioritised for drilling in the
Southern Amadeus Basin, starting in 2023, targeting hydrocarbons, helium and naturally occurring hydrogen. Relatively high helium
concentrations of 9% and 6.3% have been recorded at the existing Mt Kitty and Magee wells respectively, with Mt Kitty also registering
11.5% hydrogen. Helium concentrations above 1% can be regarded globally as high, with a concentration of greater than 0.5% regarded as
potentially economic.
Central retains an average 30% ownership interest in this major new exploration program that has enormous potential.
Dukas (EP 112)
Central – 35% interest (after farmout to Peak Helium)
Dukas is a geographically large (>400 km2) gas prospect with multi-Tcf potential located in EP 112, approximately 175 km southwest of Alice
Springs. The Dukas-1 exploration well was suspended at a depth of 3,704m in mid-2019 after encountering hydrocarbon-bearing gas from
an over-pressured zone close to the primary target. Helium and hydrogen shows were evident in association with methane and nitrogen in
mud gasses associated with the over-pressured zone. Although not from the reservoir section (which is yet to be encountered) this is an
encouraging sign of the potential presence of these gases in the reservoir zone.
Santos (operator) is planning a new Dukas well, and is currently seeking tenders for a suitable drilling rig.
Mahler (EP 82)
Central 29% interest (after farm-out to Peak Helium)
The proposed Mahler exploration well is planned to be drilled in 2023, up-dip and approximately 20km south-east of the Magee 1 well
which flowed hydrocarbon and helium (6.3%) gases in 1992. It is proposed that the well will evaluate the hydrocarbon, helium and
hydrogen potential of the sub-salt fractured basement and Heavitree formation (if present), and as a secondary objective, the oil potential
of the Bitter Springs Group carbonates.
The Mt Kitty-1 well, drilled in 2014, flowed hydrocarbon, helium (9%) and hydrogen (11.5%) gases. It is planned that the Mt Kitty-1 well will
be re-entered in 2023 and a lateral sidetrack drilled 500m into the fractured basement reservoir.
Mt Kitty (EP 125)
Central - 24% interest (after farm-out to Peak Helium)
Zevon (EP 115)
Central – 100% interest
association with hydrocarbon gasses.
A 2D seismic survey is being planned to further define the Zevon lead.
Southern Amadeus Basin, Northern Territory
Various Exploration Permits (see table on page 104)
In addition to the sub-salt drilling program planned to commence in 2023 and the Zevon lead, secondary reservoir objectives are present
within the post-salt units including the Areyonga Formation and Pioneer Sandstone, both of which are gas bearing at the Ooraminna
discovery which requires additional appraisal.
Central continues to mature its geological interpretations in these permits, seeking to identify a variety of other exploration play types and
targets which could be prospective for hydrocarbons and/or Helium.
Exploration Application Areas, Northern Territory
Amadeus, Pedirka and Wiso Basins — Various Areas (see table on page 104)
Central continued to evaluate a number of these areas and has been working to gain Native Title/Aboriginal Land Rights Act clearance and
secure the other necessary approvals in advance of the award of exploration permit status.
Play types and leads are also being developed for the under-explored sedimentary section underlying the proven Ordovician Larapintine
system. This deeper section is believed to be prospective for gas.
ATP909, ATP911 and ATP912
Southern Georgina Basin, Queensland
(CTP—100% interest)
Having reviewed the data acquired from previous activities, Central is currently reviewing its plans for the Southern Georgina Basin.
16
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
17
OPERATING AND FINANCIAL REVIEW
Farmout stimulates major sub-salt exploration program
In February, Central entered into a farmout of interests in three Amadeus Basin exploration tenements to Peak Helium (Amadeus Basin)
Pty Ltd (Peak). Under the farmout, Central will be free carried (i.e. funded) by Peak for two new sub-salt exploration wells (capped at
$20 million gross cost per well), one at Mt Kitty (EP 125) and the other at the Mahler prospect (EP 82).
Mt Kitty (EP 125)
Central - 24% interest (after farm-out to Peak Helium)
The Mt Kitty-1 well, drilled in 2014, flowed hydrocarbon, helium (9%) and hydrogen (11.5%) gases. It is planned that the Mt Kitty-1 well will
be re-entered in 2023 and a lateral sidetrack drilled 500m into the fractured basement reservoir.
Zevon (EP 115)
Central – 100% interest
The Zevon sub-salt lead in EP115 has been defined as a potentially very large closure (circa 1,600 km2) from seismic and gravity studies. It is
located in the north-western section of the Amadeus Basin between the Mereenie oil & gas field and the Surprise oil field.
Regional geological play mapping has highlighted that this area has the potential to be highly prospective for helium and hydrogen in
association with hydrocarbon gasses.
A 2D seismic survey is being planned to further define the Zevon lead.
Southern Amadeus Basin, Northern Territory
Various Exploration Permits (see table on page 104)
In addition to the sub-salt drilling program planned to commence in 2023 and the Zevon lead, secondary reservoir objectives are present
within the post-salt units including the Areyonga Formation and Pioneer Sandstone, both of which are gas bearing at the Ooraminna
discovery which requires additional appraisal.
Central continues to mature its geological interpretations in these permits, seeking to identify a variety of other exploration play types and
targets which could be prospective for hydrocarbons and/or Helium.
Exploration Application Areas, Northern Territory
Amadeus, Pedirka and Wiso Basins — Various Areas (see table on page 104)
Central continued to evaluate a number of these areas and has been working to gain Native Title/Aboriginal Land Rights Act clearance and
secure the other necessary approvals in advance of the award of exploration permit status.
Play types and leads are also being developed for the under-explored sedimentary section underlying the proven Ordovician Larapintine
system. This deeper section is believed to be prospective for gas.
ATP909, ATP911 and ATP912
Southern Georgina Basin, Queensland
(CTP—100% interest)
Having reviewed the data acquired from previous activities, Central is currently reviewing its plans for the Southern Georgina Basin.
Location of sub-salt targets
Combined with the planned Dukas exploration well, a total of three sub-salt exploration wells will now be prioritised for drilling in the
Southern Amadeus Basin, starting in 2023, targeting hydrocarbons, helium and naturally occurring hydrogen. Relatively high helium
concentrations of 9% and 6.3% have been recorded at the existing Mt Kitty and Magee wells respectively, with Mt Kitty also registering
11.5% hydrogen. Helium concentrations above 1% can be regarded globally as high, with a concentration of greater than 0.5% regarded as
potentially economic.
Central retains an average 30% ownership interest in this major new exploration program that has enormous potential.
Dukas (EP 112)
Central – 35% interest (after farmout to Peak Helium)
Dukas is a geographically large (>400 km2) gas prospect with multi-Tcf potential located in EP 112, approximately 175 km southwest of Alice
Springs. The Dukas-1 exploration well was suspended at a depth of 3,704m in mid-2019 after encountering hydrocarbon-bearing gas from
an over-pressured zone close to the primary target. Helium and hydrogen shows were evident in association with methane and nitrogen in
mud gasses associated with the over-pressured zone. Although not from the reservoir section (which is yet to be encountered) this is an
encouraging sign of the potential presence of these gases in the reservoir zone.
Santos (operator) is planning a new Dukas well, and is currently seeking tenders for a suitable drilling rig.
Mahler (EP 82)
Central 29% interest (after farm-out to Peak Helium)
The proposed Mahler exploration well is planned to be drilled in 2023, up-dip and approximately 20km south-east of the Magee 1 well
which flowed hydrocarbon and helium (6.3%) gases in 1992. It is proposed that the well will evaluate the hydrocarbon, helium and
hydrogen potential of the sub-salt fractured basement and Heavitree formation (if present), and as a secondary objective, the oil potential
of the Bitter Springs Group carbonates.
16
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
17
OPERATING AND FINANCIAL REVIEW
COMMERCIAL
Commercial activities during the year focussed on managing Central’s asset portfolio to leverage existing ownership equity to fund
development and exploration growth activities. The completion of the partial sell-down of the Amadeus production assets in October 2021
was the catalyst for several infield development and exploration programs. Central also farmed-out partial interests in three exploration
permits to enable drilling of three major sub-salt exploration wells, starting in 2023, targeting helium, naturally occurring hydrogen and
hydrocarbons.
Central continued to negotiate new gas sale agreements (GSAs) to replace maturing contracts and gained direct access to the deeper,
higher-priced east coast gas markets for the first time.
Sell-down of Amadeus production assets
On 1 October 2021, Central completed the sale of 50% of its interests in the Mereenie, Palm Valley and Dingo fields to New Zealand Oil &
Gas Limited (NZOG) and Cue Energy Resources Limited (Cue), recognising a book profit of $36.6 million. Cash proceeds were directed
towards the repayment of $29 million of debt and a ‘carry’ component provided approximately $30 million to fund Central’s share of
development and exploration activity in those fields, including the Palm Valley 12 exploration / appraisal well. NZOG and Cue also assumed
obligations to supply up to 4 PJ of gas (50% interest acquired at completion) under existing gas pre-sale and accumulated take-or-pay
arrangements, valued at $20.2 million at the completion date.
Farmout to fund two new sub-salt exploration wells in the Amadeus Basin
In February 2022, Central announced it had entered into a farmout of partial interests in three Amadeus Basin exploration tenements to
Peak Helium (Amadeus Basin) Pty Ltd (Peak). This arrangement will see accelerated drilling of three sub-salt exploration wells in the
Southern Amadeus Basin, starting in 2023.
Under the farmout, Central will be free carried by Peak for its share of the cost of two new sub-salt exploration wells (capped at $20 million
gross cost per well), one at Mt Kitty (EP125) and the other at the Mahler prospect (EP82). Peak will also join Central and Santos to drill a
new Dukas exploration well in EP112.
In consideration for the two carried wells, Peak will earn partial interests in the following permits:
31% in EP82, excluding the Dingo Satellite Area (Central’s interest will change from 60% to 29%)
10% in EP112 (Central’s interests will change from 45% to 35%)
6% in EP125 (Central’s interest will change from 30% to 24%).
•
•
•
New Gas Sales Agreement
Central executed a new GSA for the supply of 3.15 PJ of gas (Central’s share) to the Northern Territory’s Power and Water Corporation via a
back-to-back GSA with Macquarie Mereenie Pty Limited.
The four-year supply term commenced on 1 January 2022, commercialising a portion of the increased production brought online from the
2021 Mereenie development campaign. The GSA is for firm supply, with take or pay provisions and a fixed price subject to annual CPI
escalation.
Gas sales commence into the east coast trading markets
In May, Central and the other Mereenie Joint Venture participants secured as-available transportation and market trading arrangements
that allow for the sale of non-firm gas from the Mereenie gas field into the east coast trading hubs, including the Brisbane and Sydney
Short Term Trading Markets (STTMs) enabling it to broaden its customer base and increase the average price for uncontracted gas.
These arrangements enabled Central to supply 61 TJ (Central share) of gas into spot markets in May and June at an average delivered price
of $34/GJ, generating over $2m (CTP share) in revenue from uncontracted production.
In managing its business activities, Central Petroleum is committed to maintaining the highest environmental, social and governance standards
ESG AND COMMUNITY
across its operations.
As embodied in our core values:
We put safety first
•
•
•
Environmental
We respect the environment and the communities we work with
We value our people and stakeholders.
We operate in some of Australia’s most stunning and pristine environments, rich in indigenous culture with diverse flora and fauna.
As custodians of the land on which we operate, we aim to uphold the highest environmental standards and leave the smallest footprint, so that
when we finish extracting unseen resources from far beneath the surface, the land will be just as we found it, for future generations to enjoy.
We operate under some of the most stringent environmental regulations in Australia. Our operations are conducted under comprehensive
government-approved Environmental Management Plans (EMPs) in compliance with all relevant Commonwealth and State legislation. The
EMPs typically set out detailed requirements for all aspects of environmental protection, including levels for water and waste
management, air emissions, land disturbance and rehabilitation, soil and flora/fauna conservation including pest and weed control as well
as bushfire prevention.
compliance.
We have had several visits and inspections during the year by multiple regulatory agencies to monitor environmental conditions associated
with our operations and drilling programs. These visits and inspections complement our own internal monitoring and assurance programs.
Audit of compliance with our environmental conditions outlined in the various EMPs over the course of the year identified over 99%
No fracture stimulation (fracking) activities are conducted in our production or exploration areas.
18
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
19
Palm Valley
by Phil Allen
COMMERCIAL
ESG AND COMMUNITY
In managing its business activities, Central Petroleum is committed to maintaining the highest environmental, social and governance standards
across its operations.
As embodied in our core values:
We put safety first
We respect the environment and the communities we work with
We value our people and stakeholders.
•
•
•
Environmental
We operate in some of Australia’s most stunning and pristine environments, rich in indigenous culture with diverse flora and fauna.
As custodians of the land on which we operate, we aim to uphold the highest environmental standards and leave the smallest footprint, so that
when we finish extracting unseen resources from far beneath the surface, the land will be just as we found it, for future generations to enjoy.
We operate under some of the most stringent environmental regulations in Australia. Our operations are conducted under comprehensive
government-approved Environmental Management Plans (EMPs) in compliance with all relevant Commonwealth and State legislation. The
EMPs typically set out detailed requirements for all aspects of environmental protection, including levels for water and waste
management, air emissions, land disturbance and rehabilitation, soil and flora/fauna conservation including pest and weed control as well
as bushfire prevention.
We have had several visits and inspections during the year by multiple regulatory agencies to monitor environmental conditions associated
with our operations and drilling programs. These visits and inspections complement our own internal monitoring and assurance programs.
Audit of compliance with our environmental conditions outlined in the various EMPs over the course of the year identified over 99%
compliance.
No fracture stimulation (fracking) activities are conducted in our production or exploration areas.
OPERATING AND FINANCIAL REVIEW
Commercial activities during the year focussed on managing Central’s asset portfolio to leverage existing ownership equity to fund
development and exploration growth activities. The completion of the partial sell-down of the Amadeus production assets in October 2021
was the catalyst for several infield development and exploration programs. Central also farmed-out partial interests in three exploration
permits to enable drilling of three major sub-salt exploration wells, starting in 2023, targeting helium, naturally occurring hydrogen and
hydrocarbons.
Central continued to negotiate new gas sale agreements (GSAs) to replace maturing contracts and gained direct access to the deeper,
higher-priced east coast gas markets for the first time.
Sell-down of Amadeus production assets
On 1 October 2021, Central completed the sale of 50% of its interests in the Mereenie, Palm Valley and Dingo fields to New Zealand Oil &
Gas Limited (NZOG) and Cue Energy Resources Limited (Cue), recognising a book profit of $36.6 million. Cash proceeds were directed
towards the repayment of $29 million of debt and a ‘carry’ component provided approximately $30 million to fund Central’s share of
development and exploration activity in those fields, including the Palm Valley 12 exploration / appraisal well. NZOG and Cue also assumed
obligations to supply up to 4 PJ of gas (50% interest acquired at completion) under existing gas pre-sale and accumulated take-or-pay
arrangements, valued at $20.2 million at the completion date.
Farmout to fund two new sub-salt exploration wells in the Amadeus Basin
In February 2022, Central announced it had entered into a farmout of partial interests in three Amadeus Basin exploration tenements to
Peak Helium (Amadeus Basin) Pty Ltd (Peak). This arrangement will see accelerated drilling of three sub-salt exploration wells in the
Southern Amadeus Basin, starting in 2023.
Under the farmout, Central will be free carried by Peak for its share of the cost of two new sub-salt exploration wells (capped at $20 million
gross cost per well), one at Mt Kitty (EP125) and the other at the Mahler prospect (EP82). Peak will also join Central and Santos to drill a
new Dukas exploration well in EP112.
In consideration for the two carried wells, Peak will earn partial interests in the following permits:
31% in EP82, excluding the Dingo Satellite Area (Central’s interest will change from 60% to 29%)
10% in EP112 (Central’s interests will change from 45% to 35%)
6% in EP125 (Central’s interest will change from 30% to 24%).
New Gas Sales Agreement
•
•
•
back-to-back GSA with Macquarie Mereenie Pty Limited.
Central executed a new GSA for the supply of 3.15 PJ of gas (Central’s share) to the Northern Territory’s Power and Water Corporation via a
The four-year supply term commenced on 1 January 2022, commercialising a portion of the increased production brought online from the
2021 Mereenie development campaign. The GSA is for firm supply, with take or pay provisions and a fixed price subject to annual CPI
escalation.
Gas sales commence into the east coast trading markets
In May, Central and the other Mereenie Joint Venture participants secured as-available transportation and market trading arrangements
that allow for the sale of non-firm gas from the Mereenie gas field into the east coast trading hubs, including the Brisbane and Sydney
Short Term Trading Markets (STTMs) enabling it to broaden its customer base and increase the average price for uncontracted gas.
These arrangements enabled Central to supply 61 TJ (Central share) of gas into spot markets in May and June at an average delivered price
of $34/GJ, generating over $2m (CTP share) in revenue from uncontracted production.
18
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
19
Palm Valley
by Phil Allen
OPERATING AND FINANCIAL REVIEW
Climate change and emissions
Central recognises that climate change is an increasingly significant environmental, social, and business issue. While there is growing
pressure to accelerate the transition to renewable energy, the volatile energy markets experienced by east coast businesses and residents
in the winter of 2022 have highlighted the critical role that natural gas will play providing cleaner, affordable, and reliable energy as we
transition to a lower-emission energy future.
We have a social responsibility to contribute towards Australia’s energy security by providing energy to businesses and residents across the
Northern Territory and eastern states until reliable renewable energy can be introduced. The residents of Alice Springs rely on our gas
every day to generate electricity which protects them from central Australia’s soaring summer temperatures and bitterly cold winter
nights. Remote mine sites rely on our gas to supply rare minerals to worldwide markets and Central supplied 61 TJ of gas into eastern
markets in May and June 2022 when electricity and gas supplies were critically short.
The regulatory, scientific, and social response to climate change continues to evolve and, in this context, we continue to seek ways to
minimise our carbon emissions while also providing affordable, reliable energy to our customers.
We report our greenhouse emissions under the National Greenhouse and Energy Reporting Act 2007 (NGER). In the most recent completed
reporting period, FY2021, our share of scope 1 and 2 emissions across our operations was 51,198 tons of CO2e (47,545 tons in FY2020).
We are working on several initiatives to reduce our emissions, including a flare gas recovery project at Mereenie, which will seek to reduce
flare gas emissions by more than 25% and overall emissions at these sites by approximately 10%, based on current emissions. We expect to
have these modifications operational in early 2023. As older legacy equipment is replaced, we are installing more efficient appliances which
will further reduce Scope 1 emissions across our operations.
Central is also investigating the possibility of using the depleted reservoirs in its long-producing Amadeus Basin fields for carbon capture
and storage (CCS) in conjunction with potential CCS projects in the area.
Reserves and Resources by Field
Safety
At Central, the safety of our employees, contractors and the community are paramount.
During the year, over 320,066 hours were worked, with two recordable injuries, resulting in a Total Recordable Injury Frequency Rate
(TRIFR) at 30 June of 6.2.
Central is committed to protecting workers and other persons against harm to their health, safety and welfare through the elimination or
minimisation of risks arising from our operations.
Community
Central works closely with the communities in which it operates. We rely on the support of our local communities, landowners, and other
stakeholders, and we seek to provide employment and business opportunities to our local communities.
In the Northern Territory, for example:
53% of our staff live locally
23% of our staff are indigenous
Central paid over $4.5M of Royalties and fees to the Northern Territory and Central Land Council in FY2022
Central and partners spent over $4.0M with local contractors and businesses in FY2022.
•
•
•
•
We aim to pay all of our suppliers on time in accordance with the agreed terms, which usually would not exceed 30 days after the end of
the month of invoicing.
Many of Central’s operations in the NT are located on or near Indigenous lands and we recognise, embrace, and respect the Indigenous
historical, legal and heritage ties to these lands. We are committed to engage openly with the Traditional Owners and provide employment
and training opportunities to the Indigenous people. We work closely with the Central Land Council and Aboriginal Areas Protection
Authority to ensure our operations do not disturb areas of cultural heritage significance.
RESERVES AND RESOURCES STATEMENT
Net proved & probable (2P) oil and gas reserves were 73.3 PJe at 30 June 2022.
Aggregate Reserves and Resources
As at
30/06/2021
01/07/2021 to
30/06/2022
Production
Disposal
Other
As at
Comprising1
adjustment
adjustments 30/06/2022 Developed Undeveloped
Oil
Proved reserves (1P)
mmbbl
0.69
Proved plus probable
reserves (2P)
mmbbl
0.89
(0.05)
(0.05)
(0.33)
(0.43)
0.06
0.01
Contingent Resources (2C) mmbbl
0.10
—
(0.05)
—
0.37
0.41
0.05
0.35
0.40
—
Gas
Proved reserves (1P)
Proved plus probable
reserves (2P)
Contingent Resources (2C)
PJ
PJ
PJ
114.18
146.50
239.88
(5.26)
(5.26)
—
(57.63)
(73.79)
(52.44)
6.69
3.50
—
57.99
70.96
44.92
54.66
187.49
—
1
All developed and undeveloped 1P and 2P reserves are located in the Amadeus Basin geographical area.
As at
30/06/2021
01/07/2021 to
30/06/2022
Production
Disposal
Adjustment
Other
As at
Adjustments
30/06/2022
Mereenie, oil
Proved reserves (1P)
Proved plus probable reserves (2P)
Contingent Resources (2C)
mmbbl
mmbbl
mmbbl
Mereenie, gas
Proved reserves (1P)
Proved plus probable reserves (2P)
Contingent Resources (2C)
Palm Valley
Proved reserves (1P)
Proved plus probable reserves (2P)
Contingent Resources (2C)
Dingo
Proved reserves (1P)
Proved plus probable reserves (2P)
Range (Surat Basin, Qld)
Contingent Resources (2C)
PJ
PJ
PJ
PJ
PJ
PJ
PJ
PJ
0.69
0.89
0.10
64.65
87.22
91.20
21.49
24.42
13.68
28.04
34.86
Note: Estimates may not arithmetically balance due to rounding.
(0.05)
(0.05)
—
(2.88)
(2.88)
—
(1.52)
(1.52)
—
(0.85)
(0.85)
(0.33)
(0.43)
(0.05)
(33.38)
(44.67)
(45.60)
(10.40)
(11.87)
(6.84)
(13.84)
(17.25)
0.06
0.01
—
2.07
(0.46)
—
1.73
1.70
—
2.89
2.26
PJ
135.05
—
—
—
135.05
Qualified Petroleum Reserves and Resources Evaluator Statement
The information contained in this Reserves and Resources Statement is based on, and fairly represents, information and supporting
documentation reviewed by Mr Kevan Quammie who is a full-time employee of Central Petroleum holding the position of Exploration and
Development Manager. Mr Quammie holds an M.Sc. Petroleum and Natural Gas Engineering from the Pennsylvania State University, is a
member in good standing of the Society of Petroleum Engineers, is qualified in accordance with ASX listing rule 5.41. and has consented to
the inclusion of this information in the form and context in which it appears.
0.02
0.02
—
13.07
16.29
—
0.37
0.41
0.05
30.46
39.21
45.60
11.29
12.73
6.84
16.23
19.02
20
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
21
OPERATING AND FINANCIAL REVIEW
Climate change and emissions
Central recognises that climate change is an increasingly significant environmental, social, and business issue. While there is growing
pressure to accelerate the transition to renewable energy, the volatile energy markets experienced by east coast businesses and residents
in the winter of 2022 have highlighted the critical role that natural gas will play providing cleaner, affordable, and reliable energy as we
transition to a lower-emission energy future.
We have a social responsibility to contribute towards Australia’s energy security by providing energy to businesses and residents across the
Northern Territory and eastern states until reliable renewable energy can be introduced. The residents of Alice Springs rely on our gas
every day to generate electricity which protects them from central Australia’s soaring summer temperatures and bitterly cold winter
nights. Remote mine sites rely on our gas to supply rare minerals to worldwide markets and Central supplied 61 TJ of gas into eastern
markets in May and June 2022 when electricity and gas supplies were critically short.
The regulatory, scientific, and social response to climate change continues to evolve and, in this context, we continue to seek ways to
minimise our carbon emissions while also providing affordable, reliable energy to our customers.
We report our greenhouse emissions under the National Greenhouse and Energy Reporting Act 2007 (NGER). In the most recent completed
reporting period, FY2021, our share of scope 1 and 2 emissions across our operations was 51,198 tons of CO2e (47,545 tons in FY2020).
We are working on several initiatives to reduce our emissions, including a flare gas recovery project at Mereenie, which will seek to reduce
flare gas emissions by more than 25% and overall emissions at these sites by approximately 10%, based on current emissions. We expect to
have these modifications operational in early 2023. As older legacy equipment is replaced, we are installing more efficient appliances which
will further reduce Scope 1 emissions across our operations.
RESERVES AND RESOURCES STATEMENT
Net proved & probable (2P) oil and gas reserves were 73.3 PJe at 30 June 2022.
Aggregate Reserves and Resources
As at
30/06/2021
01/07/2021 to
30/06/2022
Production
Disposal
adjustment
Other
As at
Comprising1
adjustments 30/06/2022 Developed Undeveloped
Oil
Proved reserves (1P)
Proved plus probable
reserves (2P)
mmbbl
0.69
mmbbl
0.89
(0.05)
(0.05)
(0.33)
(0.43)
0.06
0.01
Contingent Resources (2C) mmbbl
0.10
—
(0.05)
—
0.37
0.41
0.05
0.35
0.40
—
Gas
Proved reserves (1P)
Proved plus probable
reserves (2P)
Contingent Resources (2C)
PJ
PJ
PJ
114.18
146.50
239.88
(5.26)
(5.26)
—
(57.63)
(73.79)
(52.44)
6.69
3.50
—
57.99
70.96
44.92
54.66
187.49
—
0.02
0.02
—
13.07
16.29
—
1
All developed and undeveloped 1P and 2P reserves are located in the Amadeus Basin geographical area.
Central is also investigating the possibility of using the depleted reservoirs in its long-producing Amadeus Basin fields for carbon capture
and storage (CCS) in conjunction with potential CCS projects in the area.
Reserves and Resources by Field
Safety
(TRIFR) at 30 June of 6.2.
At Central, the safety of our employees, contractors and the community are paramount.
During the year, over 320,066 hours were worked, with two recordable injuries, resulting in a Total Recordable Injury Frequency Rate
Central is committed to protecting workers and other persons against harm to their health, safety and welfare through the elimination or
Mereenie, oil
Proved reserves (1P)
Proved plus probable reserves (2P)
Contingent Resources (2C)
mmbbl
mmbbl
mmbbl
As at
30/06/2021
01/07/2021 to
30/06/2022
Production
Disposal
Adjustment
Other
Adjustments
As at
30/06/2022
0.69
0.89
0.10
64.65
87.22
91.20
21.49
24.42
13.68
28.04
34.86
(0.05)
(0.05)
—
(2.88)
(2.88)
—
(1.52)
(1.52)
—
(0.85)
(0.85)
(0.33)
(0.43)
(0.05)
(33.38)
(44.67)
(45.60)
(10.40)
(11.87)
(6.84)
(13.84)
(17.25)
0.06
0.01
—
2.07
(0.46)
—
1.73
1.70
—
2.89
2.26
0.37
0.41
0.05
30.46
39.21
45.60
11.29
12.73
6.84
16.23
19.02
PJ
135.05
—
—
—
135.05
Mereenie, gas
Proved reserves (1P)
Proved plus probable reserves (2P)
Contingent Resources (2C)
Palm Valley
Proved reserves (1P)
Proved plus probable reserves (2P)
Contingent Resources (2C)
Dingo
Proved reserves (1P)
Proved plus probable reserves (2P)
Range (Surat Basin, Qld)
Contingent Resources (2C)
PJ
PJ
PJ
PJ
PJ
PJ
PJ
PJ
20
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
21
Note: Estimates may not arithmetically balance due to rounding.
Qualified Petroleum Reserves and Resources Evaluator Statement
The information contained in this Reserves and Resources Statement is based on, and fairly represents, information and supporting
documentation reviewed by Mr Kevan Quammie who is a full-time employee of Central Petroleum holding the position of Exploration and
Development Manager. Mr Quammie holds an M.Sc. Petroleum and Natural Gas Engineering from the Pennsylvania State University, is a
member in good standing of the Society of Petroleum Engineers, is qualified in accordance with ASX listing rule 5.41. and has consented to
the inclusion of this information in the form and context in which it appears.
Central works closely with the communities in which it operates. We rely on the support of our local communities, landowners, and other
stakeholders, and we seek to provide employment and business opportunities to our local communities.
minimisation of risks arising from our operations.
Community
In the Northern Territory, for example:
53% of our staff live locally
23% of our staff are indigenous
•
•
•
•
the month of invoicing.
Central paid over $4.5M of Royalties and fees to the Northern Territory and Central Land Council in FY2022
Central and partners spent over $4.0M with local contractors and businesses in FY2022.
We aim to pay all of our suppliers on time in accordance with the agreed terms, which usually would not exceed 30 days after the end of
Many of Central’s operations in the NT are located on or near Indigenous lands and we recognise, embrace, and respect the Indigenous
historical, legal and heritage ties to these lands. We are committed to engage openly with the Traditional Owners and provide employment
and training opportunities to the Indigenous people. We work closely with the Central Land Council and Aboriginal Areas Protection
Authority to ensure our operations do not disturb areas of cultural heritage significance.
OPERATING AND FINANCIAL REVIEW
The reserves and resources information in this document relating to:
the Mereenie, Palm Valley and Dingo fields are based on, and fairly represent information and supporting documentation reviewed by
Mr Kevan Quammie who is a full-time employee of Central Petroleum Limited holding the position of Exploration and Development
Manager and is a member in good standing of the Society of Petroleum Engineers; and
the Range Gas Project resources were first reported to the market on 20 August 2019 and are based on, and fairly represent information
and supporting documentation reviewed by Mr John Hattner who is a full-time employee of Netherland, Sewell & Associates, Inc., holding
the position of Senior Vice President and is a member in good standing of the Society of Petroleum Engineers.
•
•
Central Petroleum Limited is not aware of any new information or data that materially affects the information included in this document
and all the material assumptions and technical parameters underpinning the estimates in the relevant market announcement continue to
apply and have not materially changed.
Reserves and resources estimates are prepared by suitably qualified personnel in a manner consistent with the Petroleum Resources
Management System (PRMS) 2018 published by the Society of Petroleum Engineers (SPE). Reserves and resources estimates are reviewed
at least annually or when new technical or commercial information becomes available. Additionally, external certification is conducted
periodically.
RISK MANAGEMENT
Central Petroleum recognises that the effective management of risks inherent to our business is vital to delivering our strategic objectives,
continued growth and success. We are committed to managing risks in a proactive, robust, and effective manner, to help achieve our
objectives.
Our risk management process is designed to recognise and manage risks that have the potential to materially impact on Central’s business
objectives. This process is aligned to the international standard ISO31000 for risk management and assesses potential risks across our
business. In managing these risks, we consider impacts on the health and safety of our employees, the environment and communities in
which we operate, our financial stability, our reputation and legal and compliance obligations.
Climate change concerns are influencing a fast-changing business landscape, with emerging policies and regulations presenting both risks
and opportunities for our existing assets and growth prospects as Australia transitions towards a lower-carbon future. Our risk
management framework provides an integrated and coordinated approach to the management of climate change risks across the business.
Principal risks and uncertainties at 30 June 2022
The principal risks and uncertainties outlined in this section may materialise independently, concurrently or in combination and may impact
Central’s ability to meet its strategic objectives.
Climate change is impacting
Demand for oil and gas may subside over the
We are focused on ensuring our business is robust in
the way that the world
longer-term, impacting demand and pricing as
a potentially carbon constrained market and engage
produces and consumes
lower carbon substitutes take market share.
proactively with key industry and government
Context
Risk
Mitigation
Social and Legal License to Operate
Failure to meet stakeholder expectations can
lead to opposition and a decline in support for
both our operational activities and future
growth opportunities.
Central proactively maintains and builds our social
license to operate through the application of our
values, effective stakeholder engagement strategies,
and our regulatory compliance framework.
A significant or continuous departure from
national or local laws, regulations or approvals,
or the introduction of new laws and
regulations may result in negative social,
cultural and reputational impacts, loss of
license to operate and could impact our ability
to operate or pursue our growth strategy.
Violation of laws and regulations may expose
Central to fines, sanctions, and civil suits, and
negatively impact our reputation.
We have a robust framework in place to support our
regulatory and compliance obligations and we
continue to strengthen our regulatory compliance
framework and supporting tools.
We proactively maintain open dialogue with
governments, regulators, and stakeholders within
jurisdictions in which we operate.
Our fraud and corruption framework aims to
prevent, detect, and respond to unethical behaviour.
It incorporates policies, procedures, and training to
ensure activities are conducted ethically.
Our business performance is
underpinned by our social
license to operate, that
requires compliance with
legislation and the
maintenance of a high
standard of ethical behaviour
and social responsibility.
Our business activities are
subject to extensive
regulation and government
policy. Failure to comply may
impact our license to
operate.
Stakeholders have evolving
expectations of social
responsibility and ethical
decision making. These are
changing at a rate faster than
governments can introduce
or amend regulation.
22
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
23
Context
Growth
Risk
Mitigation
Our future growth depends
The inability to identify and commercialise
We engage experienced, skilled personnel to identify
on our ability to identify,
growth opportunities, or realise their full value,
and progress a suite of commercially attractive and
acquire, explore, appraise,
may result in a loss of shareholder value.
sustainable opportunities that complement our
and develop resources.
Unsuccessful exploration and renewal of
upstream resources may impede delivery of
existing assets, enable portfolio diversity and
optimise our commercial position.
our strategy.
Exposure to reserve depletion is addressed through
our exploration strategy. We continue to analyse
existing acreage for exploration drilling prospects.
Our ability to successfully
Central is exposed to market and industry
We utilise an established project management
deliver value adding projects
conditions - some beyond our control, which
framework which is supported by skilled and
is also critical.
may impact project delivery and lead to cost
experienced personnel to govern and deliver major
overruns or schedule delays when developing
projects.
and executing our portfolio of capital projects.
Oil and Gas Reserves
Commercialisation of
Uncertainty in hydrocarbon reserve estimation
Our reserve and resource estimates are prepared in
hydrocarbons reserves is a
and the broad range of possible recovery
accordance with the guidelines set forth in the 2018
key contributor to our long-
scenarios from existing resources could have a
Petroleum Resources Management System (PRMS).
term success.
material adverse effect on our operations and
We proactively analyse reservoir performance and
financial performance.
undertake comprehensive production and economic
modelling to determine the most likely outcomes
across our fields. We engage independent experts
periodically to provide reserve estimates.
Climate Change
energy.
Global climate change policy remains uncertain
Oil and gas produced by
and has the potential to constrain Central’s
Central are fossil fuels, the
ability to create and deliver stakeholder value
production and consumption
from the commercialisation of hydrocarbons.
of which emit greenhouse
gases.
Introduction of taxes or other charges
associated with carbon emissions may have an
adverse impact on Central’s operations,
financial performance and asset values.
stakeholders. Our future is predominantly focused
on supplying natural gas as a transitional fuel which
could see demand for gas increase in the medium
term as part of the transition to a clean energy
future compared to other energy sources.
Central also seeks value accretive opportunities to
reduce carbon emissions and/or utilize or sequester
carbon, with both Palm Valley and Mereenie
potential candidates for carbon capture and storage
(CCS).
Central has opportunities to diversify its reliance on
hydrocarbons by targeting valuable non-
hydrocarbon gases such as helium and naturally
occurring hydrogen which have been measured in
some of its exploration tenements.
It is believed that climate
There may be increased frequency of extreme
Central’s production assets are located in arid
change may result in more
weather events such as severe storms, floods,
regions not prone to cyclones, flooding or
extreme weather in the
drought and bushfires which could damage
uncontrolled bushfires. Central maintains insurance
future.
Central’s production infrastructure and
to cover weather related risks.
interrupt Central’s operations.
OPERATING AND FINANCIAL REVIEW
The reserves and resources information in this document relating to:
the Mereenie, Palm Valley and Dingo fields are based on, and fairly represent information and supporting documentation reviewed by
Mr Kevan Quammie who is a full-time employee of Central Petroleum Limited holding the position of Exploration and Development
Manager and is a member in good standing of the Society of Petroleum Engineers; and
the Range Gas Project resources were first reported to the market on 20 August 2019 and are based on, and fairly represent information
and supporting documentation reviewed by Mr John Hattner who is a full-time employee of Netherland, Sewell & Associates, Inc., holding
the position of Senior Vice President and is a member in good standing of the Society of Petroleum Engineers.
•
•
Central Petroleum Limited is not aware of any new information or data that materially affects the information included in this document
and all the material assumptions and technical parameters underpinning the estimates in the relevant market announcement continue to
apply and have not materially changed.
Reserves and resources estimates are prepared by suitably qualified personnel in a manner consistent with the Petroleum Resources
Management System (PRMS) 2018 published by the Society of Petroleum Engineers (SPE). Reserves and resources estimates are reviewed
at least annually or when new technical or commercial information becomes available. Additionally, external certification is conducted
periodically.
RISK MANAGEMENT
objectives.
Central Petroleum recognises that the effective management of risks inherent to our business is vital to delivering our strategic objectives,
continued growth and success. We are committed to managing risks in a proactive, robust, and effective manner, to help achieve our
Our risk management process is designed to recognise and manage risks that have the potential to materially impact on Central’s business
objectives. This process is aligned to the international standard ISO31000 for risk management and assesses potential risks across our
business. In managing these risks, we consider impacts on the health and safety of our employees, the environment and communities in
which we operate, our financial stability, our reputation and legal and compliance obligations.
Climate change concerns are influencing a fast-changing business landscape, with emerging policies and regulations presenting both risks
and opportunities for our existing assets and growth prospects as Australia transitions towards a lower-carbon future. Our risk
management framework provides an integrated and coordinated approach to the management of climate change risks across the business.
Principal risks and uncertainties at 30 June 2022
The principal risks and uncertainties outlined in this section may materialise independently, concurrently or in combination and may impact
Central’s ability to meet its strategic objectives.
Context
Risk
Mitigation
Social and Legal License to Operate
Our business performance is
Failure to meet stakeholder expectations can
Central proactively maintains and builds our social
underpinned by our social
lead to opposition and a decline in support for
license to operate through the application of our
license to operate, that
both our operational activities and future
values, effective stakeholder engagement strategies,
requires compliance with
growth opportunities.
and our regulatory compliance framework.
legislation and the
maintenance of a high
standard of ethical behaviour
and social responsibility.
A significant or continuous departure from
We have a robust framework in place to support our
national or local laws, regulations or approvals,
regulatory and compliance obligations and we
or the introduction of new laws and
continue to strengthen our regulatory compliance
regulations may result in negative social,
framework and supporting tools.
Our business activities are
cultural and reputational impacts, loss of
subject to extensive
license to operate and could impact our ability
regulation and government
to operate or pursue our growth strategy.
Violation of laws and regulations may expose
Central to fines, sanctions, and civil suits, and
negatively impact our reputation.
We proactively maintain open dialogue with
governments, regulators, and stakeholders within
jurisdictions in which we operate.
Our fraud and corruption framework aims to
prevent, detect, and respond to unethical behaviour.
It incorporates policies, procedures, and training to
ensure activities are conducted ethically.
policy. Failure to comply may
impact our license to
operate.
Stakeholders have evolving
expectations of social
responsibility and ethical
decision making. These are
changing at a rate faster than
governments can introduce
or amend regulation.
Context
Growth
Our future growth depends
on our ability to identify,
acquire, explore, appraise,
and develop resources.
Risk
Mitigation
The inability to identify and commercialise
growth opportunities, or realise their full value,
may result in a loss of shareholder value.
Unsuccessful exploration and renewal of
upstream resources may impede delivery of
our strategy.
Our ability to successfully
deliver value adding projects
is also critical.
Central is exposed to market and industry
conditions - some beyond our control, which
may impact project delivery and lead to cost
overruns or schedule delays when developing
and executing our portfolio of capital projects.
Oil and Gas Reserves
Commercialisation of
hydrocarbons reserves is a
key contributor to our long-
term success.
Uncertainty in hydrocarbon reserve estimation
and the broad range of possible recovery
scenarios from existing resources could have a
material adverse effect on our operations and
financial performance.
Climate Change
Climate change is impacting
the way that the world
produces and consumes
energy.
Oil and gas produced by
Central are fossil fuels, the
production and consumption
of which emit greenhouse
gases.
Demand for oil and gas may subside over the
longer-term, impacting demand and pricing as
lower carbon substitutes take market share.
Global climate change policy remains uncertain
and has the potential to constrain Central’s
ability to create and deliver stakeholder value
from the commercialisation of hydrocarbons.
Introduction of taxes or other charges
associated with carbon emissions may have an
adverse impact on Central’s operations,
financial performance and asset values.
It is believed that climate
change may result in more
extreme weather in the
future.
There may be increased frequency of extreme
weather events such as severe storms, floods,
drought and bushfires which could damage
Central’s production infrastructure and
interrupt Central’s operations.
We engage experienced, skilled personnel to identify
and progress a suite of commercially attractive and
sustainable opportunities that complement our
existing assets, enable portfolio diversity and
optimise our commercial position.
Exposure to reserve depletion is addressed through
our exploration strategy. We continue to analyse
existing acreage for exploration drilling prospects.
We utilise an established project management
framework which is supported by skilled and
experienced personnel to govern and deliver major
projects.
Our reserve and resource estimates are prepared in
accordance with the guidelines set forth in the 2018
Petroleum Resources Management System (PRMS).
We proactively analyse reservoir performance and
undertake comprehensive production and economic
modelling to determine the most likely outcomes
across our fields. We engage independent experts
periodically to provide reserve estimates.
We are focused on ensuring our business is robust in
a potentially carbon constrained market and engage
proactively with key industry and government
stakeholders. Our future is predominantly focused
on supplying natural gas as a transitional fuel which
could see demand for gas increase in the medium
term as part of the transition to a clean energy
future compared to other energy sources.
Central also seeks value accretive opportunities to
reduce carbon emissions and/or utilize or sequester
carbon, with both Palm Valley and Mereenie
potential candidates for carbon capture and storage
(CCS).
Central has opportunities to diversify its reliance on
hydrocarbons by targeting valuable non-
hydrocarbon gases such as helium and naturally
occurring hydrogen which have been measured in
some of its exploration tenements.
Central’s production assets are located in arid
regions not prone to cyclones, flooding or
uncontrolled bushfires. Central maintains insurance
to cover weather related risks.
22
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
23
OPERATING AND FINANCIAL REVIEW
Context
Community
Risk
Mitigation
Risk
Mitigation
Our proactive engagement
and support of local and
indigenous communities is at
the core of how we operate.
Our interactions with, and decisions involving
landholders, traditional owners, suppliers and
the community fails to attract and maintain the
continued support of the communities in which
we operate.
We work in conjunction with our key stakeholders
and have established programs to support and assist
the communities in which we operate through
donations, sponsorships, local procurement, training
and providing ongoing local employment and
business opportunities.
Health and Safety
Health and Safety is at the
heart of all activities and
decisions at Central.
Health and Safety incidents or accidents may
adversely impact our people, the communities
in which we operate, our reputation and/or
our licence to operate.
Potential exposure of employees and
contractors to COVID-19 could impact our
operations and the communities in which we
operate.
Health and Safety is an area of focus for Central and
our risk management framework includes auditing
and verification processes for our critical controls.
We also regularly review our operations and
activities to ensure we operate with the required
standards of safety management.
All operational activities including travel to and from
sites are managed under Pandemic Management
Plans. We continue to monitor and align our
standards and approach with guidance from various
government and health authorities.
Operating
The production and delivery
of hydrocarbon products
safely and reliably are key
elements of our operational
and financial performance
and directly impact
shareholder returns.
Reservoir / field performance is subject to
subsurface uncertainty. The actual
performance could vary from that forecasted,
which may result in diminished production and
/or additional development costs.
We continually monitor field performance and
schedule production optimisation and development
activities to extract maximum value from the field
and to mitigate any potential reservoir under-
performance.
Our facilities are subject to hazards associated
with the production of gas and petroleum,
including major accident events such as spills
and leaks which can result in a loss of
hydrocarbon containment, diminished
production, additional costs, environmental
damage or harm to our people, reputation or
brand.
Embedded within our operational practices is a
framework of controls which enable the
management of these risks. We have in place asset
integrity management processes, inspections,
maintenance procedures and performance standards
across all activities and infrastructure to maximise
reliable and safe operations.
Central maintains insurance in line with industry
practice considered sufficient to cover normal
operational risks. However, Central is not insured
against all potential risks because not all risks can be
insured cost effectively. Insurance coverage is
determined by the availability of commercial options
and cost/ benefit analysis, considering Central’s risk
management program.
In addition, our operations can be negatively
impacted by employee and contractor
availability due to the impacts associated with
COVID-19 including shutting down for a period.
All operational employee and contractor activities
are managed under Pandemic Management Plans
aligned with the relevant regulatory requirements to
minimise the risk to people and operations.
People and Culture
We must have the right
capability and capacity within
our business through
personnel who are engaged
and enabled to deliver our
current business and future
growth opportunities.
Failure to establish and develop sufficient
capability and capacity to support our
operations may impact achievement of our
objectives.
We are focussed on securing and developing the
right people to support the operation and
development of our portfolio of assets and
opportunities. We also proactively engage
contractors to supplement any short-term gaps in
capability and capacity to support the execution of
our business plans.
Context
Financial
Our financial strength and
Insufficient liquidity to meet financial
We have a robust expenditure management and
performance underpins our
commitments and fund growth opportunities
forecasting process which is monitored against a
strategy and future growth.
could have a material adverse effect on our
Board approved budget to ensure capital is allocated
operations and financial performance.
in accordance with the company’s strategy. We
actively manage debt and other funding sources to
ensure the business is appropriately capitalised to
sustain ongoing operations and growth plans. We
also actively seek partnering opportunities to share
risks and assist in funding key activities on a project-
by-project basis.
Our revenue is from the sale
Central is exposed to USD commodity price
Oil revenue represented less than 15% of
of hydrocarbons. This
variability with respect to crude oil sales which
consolidated sales revenue in FY2022.
underpins Central’s financial
are impacted by broader economic factors
performance.
beyond our control.
The majority of Central’s revenue is from natural gas
sales denominated in AUD and the short-term
Central is exposed to gas commodity prices
uncertainty with this commodity is largely mitigated
with respect to gas sales, all of which are to the
through medium and long term fixed-price gas sales
Northern Territory and Australian east coast
agreements with ‘take-or-pay’ provisions.
markets. In addition to normal demand and
supply forces, gas prices in these markets are
subject to risk of Government intervention,
including the Australian Domestic Gas Supply
Mechanism; although this mechanism is
focused on availability of supply and may not
have a significant impact on price.
Environment
Our environmental
Our operations by their nature have the
Environmental management is a very high priority
performance underpins our
potential to impact air quality, biodiversity,
for Central. We operate under approved Field
licence to operate.
land and water resources and related
Environmental Management Plans and have a
ecosystems. A failure to manage these could
program of regular environmental inspections and
adversely impact not just the environment, but
audits in place to ensure compliance. We also
our people, the communities in which we
continue to assess and develop our standards to
operate, our reputation and our licence to
prevent, monitor and limit the impact of our
operate.
operations on the environment.
We carry third party environmental liability
insurance in addition to well control insurance to
mitigate financial impacts should an event occur.
Digital and Cyber Security
support the business
operating safely and
effectively.
sophistication.
We are reliant upon our
Failure to safeguard the confidentiality,
Digital risks are identified, assessed and managed
systems and infrastructure
integrity, availability and reliability of digital
based on the business criticality of our systems,
availability and reliability to
data and intellectual property.
which may be segregated and isolated if required.
Central’s information and operational
We continuously assess and determine access
technology systems may be subject to
permissions to critical information or data, whilst
intentional or unintentional disruption (e.g.
consolidating, simplifying, and automating security
Cyber risks continue to evolve
cyber security attack) which could impact our
controls.
with greater levels of
ability to reliably supply customers.
Our exposure to cyber risk is managed by a proactive
and continuing focus on system controls such as
firewalls, restricted points of entry, multifactor
authentication, multiple data back-ups and security
monitoring software. We are continuing to embed a
cyber-safe culture across Central.
24
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
25
OPERATING AND FINANCIAL REVIEW
Context
Community
Risk
Mitigation
Our proactive engagement
Our interactions with, and decisions involving
We work in conjunction with our key stakeholders
and support of local and
landholders, traditional owners, suppliers and
and have established programs to support and assist
indigenous communities is at
the community fails to attract and maintain the
the communities in which we operate through
the core of how we operate.
continued support of the communities in which
donations, sponsorships, local procurement, training
we operate.
and providing ongoing local employment and
business opportunities.
Health and Safety
Health and Safety is at the
Health and Safety incidents or accidents may
Health and Safety is an area of focus for Central and
heart of all activities and
adversely impact our people, the communities
our risk management framework includes auditing
decisions at Central.
in which we operate, our reputation and/or
and verification processes for our critical controls.
our licence to operate.
We also regularly review our operations and
activities to ensure we operate with the required
standards of safety management.
Potential exposure of employees and
All operational activities including travel to and from
contractors to COVID-19 could impact our
sites are managed under Pandemic Management
operations and the communities in which we
Plans. We continue to monitor and align our
operate.
standards and approach with guidance from various
government and health authorities.
The production and delivery
Reservoir / field performance is subject to
We continually monitor field performance and
of hydrocarbon products
subsurface uncertainty. The actual
schedule production optimisation and development
safely and reliably are key
performance could vary from that forecasted,
activities to extract maximum value from the field
elements of our operational
which may result in diminished production and
and to mitigate any potential reservoir under-
and financial performance
/or additional development costs.
performance.
Operating
and directly impact
shareholder returns.
Our facilities are subject to hazards associated
Embedded within our operational practices is a
with the production of gas and petroleum,
framework of controls which enable the
including major accident events such as spills
management of these risks. We have in place asset
and leaks which can result in a loss of
integrity management processes, inspections,
hydrocarbon containment, diminished
maintenance procedures and performance standards
production, additional costs, environmental
across all activities and infrastructure to maximise
damage or harm to our people, reputation or
reliable and safe operations.
brand.
Central maintains insurance in line with industry
practice considered sufficient to cover normal
operational risks. However, Central is not insured
against all potential risks because not all risks can be
insured cost effectively. Insurance coverage is
determined by the availability of commercial options
and cost/ benefit analysis, considering Central’s risk
management program.
In addition, our operations can be negatively
All operational employee and contractor activities
impacted by employee and contractor
are managed under Pandemic Management Plans
availability due to the impacts associated with
aligned with the relevant regulatory requirements to
COVID-19 including shutting down for a period.
minimise the risk to people and operations.
People and Culture
We must have the right
Failure to establish and develop sufficient
We are focussed on securing and developing the
capability and capacity within
capability and capacity to support our
right people to support the operation and
our business through
operations may impact achievement of our
development of our portfolio of assets and
personnel who are engaged
objectives.
and enabled to deliver our
current business and future
growth opportunities.
opportunities. We also proactively engage
contractors to supplement any short-term gaps in
capability and capacity to support the execution of
our business plans.
Context
Financial
Risk
Mitigation
Our financial strength and
performance underpins our
strategy and future growth.
Insufficient liquidity to meet financial
commitments and fund growth opportunities
could have a material adverse effect on our
operations and financial performance.
Our revenue is from the sale
of hydrocarbons. This
underpins Central’s financial
performance.
Central is exposed to USD commodity price
variability with respect to crude oil sales which
are impacted by broader economic factors
beyond our control.
Central is exposed to gas commodity prices
with respect to gas sales, all of which are to the
Northern Territory and Australian east coast
markets. In addition to normal demand and
supply forces, gas prices in these markets are
subject to risk of Government intervention,
including the Australian Domestic Gas Supply
Mechanism; although this mechanism is
focused on availability of supply and may not
have a significant impact on price.
We have a robust expenditure management and
forecasting process which is monitored against a
Board approved budget to ensure capital is allocated
in accordance with the company’s strategy. We
actively manage debt and other funding sources to
ensure the business is appropriately capitalised to
sustain ongoing operations and growth plans. We
also actively seek partnering opportunities to share
risks and assist in funding key activities on a project-
by-project basis.
Oil revenue represented less than 15% of
consolidated sales revenue in FY2022.
The majority of Central’s revenue is from natural gas
sales denominated in AUD and the short-term
uncertainty with this commodity is largely mitigated
through medium and long term fixed-price gas sales
agreements with ‘take-or-pay’ provisions.
Environment
Our environmental
performance underpins our
licence to operate.
Digital and Cyber Security
We are reliant upon our
systems and infrastructure
availability and reliability to
support the business
operating safely and
effectively.
Cyber risks continue to evolve
with greater levels of
sophistication.
Our operations by their nature have the
potential to impact air quality, biodiversity,
land and water resources and related
ecosystems. A failure to manage these could
adversely impact not just the environment, but
our people, the communities in which we
operate, our reputation and our licence to
operate.
Environmental management is a very high priority
for Central. We operate under approved Field
Environmental Management Plans and have a
program of regular environmental inspections and
audits in place to ensure compliance. We also
continue to assess and develop our standards to
prevent, monitor and limit the impact of our
operations on the environment.
We carry third party environmental liability
insurance in addition to well control insurance to
mitigate financial impacts should an event occur.
Failure to safeguard the confidentiality,
integrity, availability and reliability of digital
data and intellectual property.
Digital risks are identified, assessed and managed
based on the business criticality of our systems,
which may be segregated and isolated if required.
Central’s information and operational
technology systems may be subject to
intentional or unintentional disruption (e.g.
cyber security attack) which could impact our
ability to reliably supply customers.
We continuously assess and determine access
permissions to critical information or data, whilst
consolidating, simplifying, and automating security
controls.
Our exposure to cyber risk is managed by a proactive
and continuing focus on system controls such as
firewalls, restricted points of entry, multifactor
authentication, multiple data back-ups and security
monitoring software. We are continuing to embed a
cyber-safe culture across Central.
24
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
25
OPERATING AND FINANCIAL REVIEW
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2022
Context
Risk
Mitigation
Geographic Concentration
We face risks associated with
the concentration of our
production assets.
Central’s revenue is derived from oil and gas
production in the Amadeus Basin leaving
Central exposed to downsides associated with
weather conditions and infrastructure failure.
We ensure that appropriate insurance is in place to
mitigate the impact of any extended business
interruption. The Range coal seam gas project in the
Surat Basin is increasing the geographical
diversification of our business. We are also
investigating other new ventures outside of the
Amadeus Basin.
Access to Infrastructure
Our financial performance
and growth strategy are
dependent on access to third
party owned infrastructure.
Negative impacts to revenue as a result of
infrastructure failure, increased tariffs, or
restricted access to third party owned
infrastructure.
We seek to work closely with customers and
suppliers of infrastructure to mitigate the risk of
delays or failure. We continue to explore alternative
routes to market to diversify risk where possible.
Joint Ventures
Although we operate most of
the tenements we hold, we
are dependent on technical
and commercial alignment
with our joint venture
partners.
Misalignment between joint venture partners
can lead to scarcity of available capital and
may impact the prioritisation of exploration,
development or production opportunities. This
can lead to delayed approvals which may
impact Central’s growth strategy.
We work closely with our joint venture partners to
achieve mutually beneficial outcomes.
The principal activities of the Consolidated Entity constituting Central Petroleum Limited and the entities it controls consists of
development, production, processing and marketing of hydrocarbons and associated exploration.
Your Directors present their report on the consolidated entity, consisting of Central Petroleum Limited (“the Company”, “Central” or “CTP”)
and the entities it controlled (collectively “the Group” or “the Consolidated Entity”) at the end of, or during, the year ended 30 June 2022.
DIRECTORS
The names of the Directors of the Company in office during the financial year and until the date of this report are set out below. Directors
were in office for this entire period unless otherwise stated.
Mr Michael (Mick) McCormack (Chair)
Mr Leon Devaney (Managing Director)
Mr Stuart Baker (resigned 30 August 2022)
Mr Stephen Gardiner
Mr Troy Harry (commenced 1 September 2022)
Ms Katherine Hirschfeld AM
Dr Agu Kantsler
PRINCIPAL ACTIVITIES
DIVIDENDS
No dividends were paid or declared during the financial year (2021: $Nil). No recommendation for payment of dividends has been made.
OPERATING AND FINANCIAL REVIEW
The operating and financial highlights for the financial year were:
•
•
•
•
•
•
•
•
•
•
On 1 October 2021 Central completed the sale of 50% of its interests in the Mereenie, Palm Valley and Dingo fields for consideration
valued at circa $85 million, recording a book profit of $36.6 million and reducing debt by $30 million around the completion date.
EBITDAX of $53.3 million.
Full year profit of $21.3 million.
Reduced net debt by 67% to $10.2 million and extended loan facility by three years to 30 September 2025.
Entered into a new gas sale agreement for the sale of 3.15 PJ of gas over four years from 1 January 2022.
The Mereenie development program was completed, with new production brought online.
Continued outperformance of the Palm Valley 13 well and Dingo gas field resulted in an increase of 3.5 PJe of 2P reserves (before
production) as at 31 December 2021.
production zone at Palm Valley.
Commenced drilling the Palm Valley 12 exploration well in April 2022. The sidetrack into the Lower P2/P3 Sandstones proved
unsuccessful in August, and a second lateral appraisal well is currently being drilled into the P1 Sandstone which is the current
Entered into a farmout of interests in the Group’s Amadeus Basin exploration tenements EP82, EP112 and EP125 with a three-well
exploration program to commence in 2023. The Group will be free-carried for its share of costs (capped at $20 million gross cost per
well) for two new sub-salt exploration wells targeting natural gas, helium and hydrogen.
In early May 2022, Central entered into gas transport and spot trading arrangements allowing for the delivery of uncontracted gas into
the Eastern Australian markets. Through May and June sales into these markets achieved an average delivered price of $34/GJ.
A detailed review of the operating and financial performance for the year ended 30 June 2022, including principal risks is provided from
pages 3 to 26 of this Annual Report.
26
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
27
OPERATING AND FINANCIAL REVIEW
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2022
Context
Risk
Mitigation
Geographic Concentration
We face risks associated with
Central’s revenue is derived from oil and gas
We ensure that appropriate insurance is in place to
the concentration of our
production in the Amadeus Basin leaving
mitigate the impact of any extended business
production assets.
Central exposed to downsides associated with
interruption. The Range coal seam gas project in the
weather conditions and infrastructure failure.
Surat Basin is increasing the geographical
diversification of our business. We are also
investigating other new ventures outside of the
Amadeus Basin.
Our financial performance
Negative impacts to revenue as a result of
We seek to work closely with customers and
and growth strategy are
infrastructure failure, increased tariffs, or
suppliers of infrastructure to mitigate the risk of
dependent on access to third
restricted access to third party owned
delays or failure. We continue to explore alternative
party owned infrastructure.
infrastructure.
routes to market to diversify risk where possible.
Access to Infrastructure
Joint Ventures
Although we operate most of
Misalignment between joint venture partners
We work closely with our joint venture partners to
the tenements we hold, we
can lead to scarcity of available capital and
achieve mutually beneficial outcomes.
are dependent on technical
may impact the prioritisation of exploration,
and commercial alignment
development or production opportunities. This
with our joint venture
can lead to delayed approvals which may
partners.
impact Central’s growth strategy.
Your Directors present their report on the consolidated entity, consisting of Central Petroleum Limited (“the Company”, “Central” or “CTP”)
and the entities it controlled (collectively “the Group” or “the Consolidated Entity”) at the end of, or during, the year ended 30 June 2022.
DIRECTORS
The names of the Directors of the Company in office during the financial year and until the date of this report are set out below. Directors
were in office for this entire period unless otherwise stated.
Mr Michael (Mick) McCormack (Chair)
Mr Leon Devaney (Managing Director)
Mr Stuart Baker (resigned 30 August 2022)
Mr Stephen Gardiner
Mr Troy Harry (commenced 1 September 2022)
Ms Katherine Hirschfeld AM
Dr Agu Kantsler
PRINCIPAL ACTIVITIES
The principal activities of the Consolidated Entity constituting Central Petroleum Limited and the entities it controls consists of
development, production, processing and marketing of hydrocarbons and associated exploration.
DIVIDENDS
No dividends were paid or declared during the financial year (2021: $Nil). No recommendation for payment of dividends has been made.
OPERATING AND FINANCIAL REVIEW
The operating and financial highlights for the financial year were:
On 1 October 2021 Central completed the sale of 50% of its interests in the Mereenie, Palm Valley and Dingo fields for consideration
valued at circa $85 million, recording a book profit of $36.6 million and reducing debt by $30 million around the completion date.
EBITDAX of $53.3 million.
Full year profit of $21.3 million.
Reduced net debt by 67% to $10.2 million and extended loan facility by three years to 30 September 2025.
Entered into a new gas sale agreement for the sale of 3.15 PJ of gas over four years from 1 January 2022.
The Mereenie development program was completed, with new production brought online.
Continued outperformance of the Palm Valley 13 well and Dingo gas field resulted in an increase of 3.5 PJe of 2P reserves (before
production) as at 31 December 2021.
Commenced drilling the Palm Valley 12 exploration well in April 2022. The sidetrack into the Lower P2/P3 Sandstones proved
unsuccessful in August, and a second lateral appraisal well is currently being drilled into the P1 Sandstone which is the current
production zone at Palm Valley.
Entered into a farmout of interests in the Group’s Amadeus Basin exploration tenements EP82, EP112 and EP125 with a three-well
exploration program to commence in 2023. The Group will be free-carried for its share of costs (capped at $20 million gross cost per
well) for two new sub-salt exploration wells targeting natural gas, helium and hydrogen.
•
•
•
•
•
•
•
•
•
In early May 2022, Central entered into gas transport and spot trading arrangements allowing for the delivery of uncontracted gas into
the Eastern Australian markets. Through May and June sales into these markets achieved an average delivered price of $34/GJ.
•
A detailed review of the operating and financial performance for the year ended 30 June 2022, including principal risks is provided from
pages 3 to 26 of this Annual Report.
26
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
27
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2022
SIGNIFICANT CHANGES IN THE STATE OF AFFAIRS
INFORMATION ON DIRECTORS
The financial position and performance of the Group was particularly affected by the following events and transactions during the year
ended 30 June 2022:
On 1 October 2021 Central completed the sale of 50% of its interests in the Mereenie, Palm Valley and Dingo fields for consideration
valued at circa $85 million, recording a book profit of $36.6 million and reducing debt by $30 million around the completion date. The
reduced interests in the production assets had a corresponding impact on revenue.
Entered into a farmout of interests in the Group’s Amadeus Basin exploration tenements EP82, EP112 and EP125. The Group will be
free-carried for its share of the costs of two new sub-salt exploration wells targeting natural gas, helium and hydrogen. Drilling is
expected to commence in 2023.
•
•
There were no other significant events that are not detailed elsewhere in this Annual Report.
EVENTS SINCE THE END OF THE FINANCIAL YEAR
No significant matters or circumstances have arisen between 30 June 2022 and the date of this report that will affect the Group’s
operations, result or state of affairs, or may do so in future years.
LIKELY DEVELOPMENTS AND EXPECTED RESULTS OF OPERATIONS
Production enhancement
The new Palm Valley 12 well is scheduled to be completed in the first half of FY2023 and tied-in to the Palm Valley processing plant to
boost Palm Valley gas production.
Production-enhancing activities are planned for the Mereenie field, with the recompletion of up to six existing wells to produce from
production zones which are currently behind pipe. Two new development wells are also being considered by the Mereenie joint venture
and could be drilled by mid-2023 to boost production capacity at Mereenie for supply into strong gas markets.
Exploration
A significant, three well sub-salt exploration campaign in the southern Amadeus Basin is also expected to commence in 2023. Operated by
Santos, and with Central’s costs in two wells to be funded by new joint venture partner, Peak Helium, (capped at $20 million gross per well)
these targets have potential for large hydrocarbon resources as well as high-value helium and naturally occurring hydrogen.
Other proposed near-term exploration activity includes an oil exploration well at Mamlambo and seismic acquisition at the large Zevon
sub-salt lead, subject to funding availability.
Appraisal
Testing of three pilot wells will continue through the first half of FY2023 at Central’s Range CSG project in Queensland and will provide data
to assist with appraisal of the permit.
Commercial
Demand for gas is expected to remain strong through FY2023, and Central expects to be able to commit to new gas supply contracts at
higher pricing than in previous periods as existing contracts mature.
Further information on these activities is included from pages 1 to 26 of this Annual Report.
As permitted by sections 299(3) and 299A(3) of the Corporations Act 2001, certain information has been omitted from the Operating and
Financial Review of this report relating to the Company’s business strategy, future prospects, likely developments in operations, and the
expected results of those operations in future financial years on the basis that such information, if disclosed, would be likely to result in an
unreasonable prejudice to Central (for example, because the information is premature, commercially sensitive, confidential or could give a
commercial advantage to a third party). The omitted information relates to internal budgets, estimates and forecasts, contractual pricing,
and business strategy.
Mr Michael (Mick) McCormack BSurv, GradDipEng, MBA, FAICD
Independent Non-executive Chair
Mr McCormack was appointed as a director on 1 September 2020 and has over 38 years’ experience in the energy
infrastructure sector in Australia and his career has encompassed all aspects of the sector, including commercial
development, design, construction, operation and management of most of Australia’s natural gas pipelines and gas
distribution systems. His experience extends to gas-fired and renewable power generation, gas processing, LNG and
underground storage.
Mr McCormack is a former Managing Director and CEO of APA Group and former Director of Envestra (now Australian
Gas Infrastructure Group), the Australian Pipeline Industry Association (now Australian Pipelines and Gas Association)
and the Australian Brandenburg Orchestra. He is a non-executive director at Origin Eneregy and Austal Limited and a
director of the Clontarf Foundation and the Australian Brandenburg Orchestra Foundation and a Fellow of the
Australian Institute of Company Directors.
Directorships of other listed companies in the last three years: Director of Austal Limited from September 2020 and
Director of Origin Energy Limited from December 2020.
Mr Leon Devaney BSc, MBA
Managing Director and Chief Executive Officer
Mr Devaney has over 20 years of commercial and finance experience within the Australian oil and gas sector and holds
an MBA and BSc (Finance) from the University of Southern California, USA.
He joined Central Petroleum in 2012 and has been responsible for commercial, finance and business development
activities in various senior roles. He was instrumental in negotiating the Mereenie acquisition from Santos in 2015 and
the Palm Valley and Dingo Gas Field acquisition from Magellan Petroleum in 2014, as well as structuring the winning
application for ATP2031 (Range Gas Project) in 2018. Mr Devaney has been a director since 14 November 2018 and was
appointed Chief Executive Officer, effective February 2019, after serving as Acting CEO since July 2018.
Prior to joining Central Petroleum, he worked at QGC and played a pivotal role in its growth from a small cap gas
exploration company into a multi-billion-dollar takeover target by the BG Group in 2008. He continued with BG
following the QGC takeover, where he served as General Manager, Gas and Power, responsible for the domestic gas
and electricity portfolio.
throughout Australia.
Prior to QGC, Mr Devaney held senior roles at Deloitte in the Corporate Finance Advisory Group where he was active in
structuring and implementing commercial and financing transactions for major energy and infrastructure projects
Mr Stephen Gardiner BEc (Hons), Fellow of CPA Australia
Independent Non-executive Director
Mr Gardiner has been a director of Central Petroleum Limited since 1 July 2021. He has over forty years of corporate
finance experience at major companies listed on the ASX, culminating in 17 years at Oil Search Limited including eight
years as Chief Financial Officer, a role that he stepped down from in March 2021.
While at Oil Search, Stephen covered a range of executive responsibilities including corporate finance and control,
treasury, tax, audit and assurance, risk management, investor relations and communications, ICT and sustainability. He
also served as Group Secretary for ten years while performing his finance roles.
Prior to Oil Search, Stephen held senior corporate finance roles at major multinational companies including CSR Limited
and Pioneer International Limited. Stephen has particular strength in capital management and funding, both debt and
equity, having raised many billions of dollars, including via structured financings such as working on the US$15 billion
PNG LNG Project financing, the largest such financing ever undertaken at the time.
Directorships of other listed companies in the last three years: ioneer Ltd from 25 August 2022.
28
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
29
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2022
The financial position and performance of the Group was particularly affected by the following events and transactions during the year
ended 30 June 2022:
On 1 October 2021 Central completed the sale of 50% of its interests in the Mereenie, Palm Valley and Dingo fields for consideration
valued at circa $85 million, recording a book profit of $36.6 million and reducing debt by $30 million around the completion date. The
reduced interests in the production assets had a corresponding impact on revenue.
Entered into a farmout of interests in the Group’s Amadeus Basin exploration tenements EP82, EP112 and EP125. The Group will be
free-carried for its share of the costs of two new sub-salt exploration wells targeting natural gas, helium and hydrogen. Drilling is
•
•
expected to commence in 2023.
There were no other significant events that are not detailed elsewhere in this Annual Report.
EVENTS SINCE THE END OF THE FINANCIAL YEAR
No significant matters or circumstances have arisen between 30 June 2022 and the date of this report that will affect the Group’s
operations, result or state of affairs, or may do so in future years.
LIKELY DEVELOPMENTS AND EXPECTED RESULTS OF OPERATIONS
The new Palm Valley 12 well is scheduled to be completed in the first half of FY2023 and tied-in to the Palm Valley processing plant to
Production enhancement
boost Palm Valley gas production.
Production-enhancing activities are planned for the Mereenie field, with the recompletion of up to six existing wells to produce from
production zones which are currently behind pipe. Two new development wells are also being considered by the Mereenie joint venture
and could be drilled by mid-2023 to boost production capacity at Mereenie for supply into strong gas markets.
Exploration
A significant, three well sub-salt exploration campaign in the southern Amadeus Basin is also expected to commence in 2023. Operated by
Santos, and with Central’s costs in two wells to be funded by new joint venture partner, Peak Helium, (capped at $20 million gross per well)
these targets have potential for large hydrocarbon resources as well as high-value helium and naturally occurring hydrogen.
Other proposed near-term exploration activity includes an oil exploration well at Mamlambo and seismic acquisition at the large Zevon
Testing of three pilot wells will continue through the first half of FY2023 at Central’s Range CSG project in Queensland and will provide data
sub-salt lead, subject to funding availability.
Appraisal
Commercial
to assist with appraisal of the permit.
Demand for gas is expected to remain strong through FY2023, and Central expects to be able to commit to new gas supply contracts at
higher pricing than in previous periods as existing contracts mature.
Further information on these activities is included from pages 1 to 26 of this Annual Report.
As permitted by sections 299(3) and 299A(3) of the Corporations Act 2001, certain information has been omitted from the Operating and
Financial Review of this report relating to the Company’s business strategy, future prospects, likely developments in operations, and the
expected results of those operations in future financial years on the basis that such information, if disclosed, would be likely to result in an
unreasonable prejudice to Central (for example, because the information is premature, commercially sensitive, confidential or could give a
commercial advantage to a third party). The omitted information relates to internal budgets, estimates and forecasts, contractual pricing,
and business strategy.
SIGNIFICANT CHANGES IN THE STATE OF AFFAIRS
INFORMATION ON DIRECTORS
Mr Michael (Mick) McCormack BSurv, GradDipEng, MBA, FAICD
Independent Non-executive Chair
Mr McCormack was appointed as a director on 1 September 2020 and has over 38 years’ experience in the energy
infrastructure sector in Australia and his career has encompassed all aspects of the sector, including commercial
development, design, construction, operation and management of most of Australia’s natural gas pipelines and gas
distribution systems. His experience extends to gas-fired and renewable power generation, gas processing, LNG and
underground storage.
Mr McCormack is a former Managing Director and CEO of APA Group and former Director of Envestra (now Australian
Gas Infrastructure Group), the Australian Pipeline Industry Association (now Australian Pipelines and Gas Association)
and the Australian Brandenburg Orchestra. He is a non-executive director at Origin Eneregy and Austal Limited and a
director of the Clontarf Foundation and the Australian Brandenburg Orchestra Foundation and a Fellow of the
Australian Institute of Company Directors.
Directorships of other listed companies in the last three years: Director of Austal Limited from September 2020 and
Director of Origin Energy Limited from December 2020.
Mr Leon Devaney BSc, MBA
Managing Director and Chief Executive Officer
Mr Devaney has over 20 years of commercial and finance experience within the Australian oil and gas sector and holds
an MBA and BSc (Finance) from the University of Southern California, USA.
He joined Central Petroleum in 2012 and has been responsible for commercial, finance and business development
activities in various senior roles. He was instrumental in negotiating the Mereenie acquisition from Santos in 2015 and
the Palm Valley and Dingo Gas Field acquisition from Magellan Petroleum in 2014, as well as structuring the winning
application for ATP2031 (Range Gas Project) in 2018. Mr Devaney has been a director since 14 November 2018 and was
appointed Chief Executive Officer, effective February 2019, after serving as Acting CEO since July 2018.
Prior to joining Central Petroleum, he worked at QGC and played a pivotal role in its growth from a small cap gas
exploration company into a multi-billion-dollar takeover target by the BG Group in 2008. He continued with BG
following the QGC takeover, where he served as General Manager, Gas and Power, responsible for the domestic gas
and electricity portfolio.
Prior to QGC, Mr Devaney held senior roles at Deloitte in the Corporate Finance Advisory Group where he was active in
structuring and implementing commercial and financing transactions for major energy and infrastructure projects
throughout Australia.
Mr Stephen Gardiner BEc (Hons), Fellow of CPA Australia
Independent Non-executive Director
Mr Gardiner has been a director of Central Petroleum Limited since 1 July 2021. He has over forty years of corporate
finance experience at major companies listed on the ASX, culminating in 17 years at Oil Search Limited including eight
years as Chief Financial Officer, a role that he stepped down from in March 2021.
While at Oil Search, Stephen covered a range of executive responsibilities including corporate finance and control,
treasury, tax, audit and assurance, risk management, investor relations and communications, ICT and sustainability. He
also served as Group Secretary for ten years while performing his finance roles.
Prior to Oil Search, Stephen held senior corporate finance roles at major multinational companies including CSR Limited
and Pioneer International Limited. Stephen has particular strength in capital management and funding, both debt and
equity, having raised many billions of dollars, including via structured financings such as working on the US$15 billion
PNG LNG Project financing, the largest such financing ever undertaken at the time.
Directorships of other listed companies in the last three years: ioneer Ltd from 25 August 2022.
28
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
29
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2022
INFORMATION ON DIRECTORS (CONTINUED)
DIRECTORS’ MEETINGS
Mr Troy Harry
Non-executive Director
Mr Harry was appointed as a director on 1 September 2022. He is a professional investor with interests in many ASX
listed companies, as well as private businesses and property. He formerly had a career in stockbroking and funds
management and was the founder of Trojan Investment Management Pty Ltd.
Troy is currently a director of numerous private entities and of The MND and Me Foundation Limited. He has not held
any other ASX directorships in the last 3 years.
Through his associated entities, Troy is a substantial shareholder in Central Petroleum Limited.
Ms Katherine Hirschfeld AM BE(Chem) UQ, HonFIEAust, FTSE, FIChemE, FAICD
Independent Non-executive Director
Ms Hirschfeld was appointed as a director on 7 December 2018 and is a highly regarded non-executive director, having
served on company boards listed on the ASX, NZX and NYSE, as well as government and private company boards. She is
currently the Chair of Powerlink and a board member of Spark Infrastructure RE Limited, its subsidiaries and related
entities (which includes the Boards of SA Power Networks and Victoria Power Networks (Powercor and CityPower)).
Ms Hirschfeld has also been a board member and President of UN Women National Committee Australia and non-
executive director of Energy Queensland, Tox Free Solutions, InterOil Corporation, Broadspectrum, Snowy Hydro and
Queensland Urban Utilities.
Previously she had leadership roles with BP in oil refining, logistics, exploration and production located in Australia, UK
and Turkey.
Ms Hirschfeld was recognised in the AFR/Westpac 100 Women of Influence 2015, by Engineers Australia as one of
Australia’s Top 100 Most Influential Engineers 2015 and as an Honorary Fellow in 2014. She is a member of Chief
Executive Women and a Fellow of the Australian Institute of Company Directors and the Academy of Engineering and
Technology. She is also an executive mentor/coach with Merryck & Co.
In 2019 Ms Hirschfeld was appointed a Member of the Order of Australia (AM) for significant service to engineering, to
women, and to business.
Dr Agu Kantsler BSc (Hons), PhD, GAICD, FTSE
Independent Non-executive Director
Dr Kantsler has been a director of Central Petroleum Limited since 15 June 2020 and is one of Australia’s most
respected and experienced petroleum exploration executives, having led Woodside Petroleum’s world-wide
exploration, business development and geotechnical activities as Executive Vice President Exploration and New
Ventures from 1995 to 2009.
Prior to joining Woodside, Dr Kantsler worked for Shell in various international locations and has served as Director and
Chairman of the Australian Petroleum Production & Exploration Association (APPEA).
Dr Kantsler is Managing Director of Transform Exploration Pty Ltd, a former Director or Oil Search Limited and a former
President of the Chamber of Commerce and Industry WA.
COMPANY SECRETARY
Mr Daniel White LLB, BCom, LLM
Mr White is an experienced oil and gas lawyer in corporate finance transactions, mergers and acquisitions, equity and
debt capital raisings, joint venture, farmout and partnering arrangements and dispute resolution. He has previously
held senior international based positions with Kuwait Energy Company and Clough Limited.
The numbers of meetings of the Company’s board of directors and of each board committee held during the financial year, and the
numbers of meetings attended by each Director were:
Director
Stuart Baker
Leon Devaney
Stephen Gardiner3
Katherine Hirschfeld AM
Agu Kantsler
Michael McCormack
Full Meeting of
Audit & Financial Risk
Risk & Sustainability
Remuneration &
Directors
Committee
Committee
Nominations Committee
Eligible1
Attended
Eligible1
Attended2
Eligible1
Attended2
Eligible1
Attended2
8
8
8
8
8
8
8
8
8
8
8
8
4
—
4
4
—
4
4
4
4
4
4
4
—
—
5
5
5
5
5
5
5
5
5
5
5
—
—
—
5
5
5
5
5
5
5
5
1 Number of meetings held during the time the director held office or was a member of the committee during the year.
2 The number of meetings attended includes those attended by invitation.
3 Stephen Gardiner was appointed 1 July 2021.
SHARES UNDER OPTION
of the Company.
(a) There were no options granted during or since the end of the financial year to directors and the five most highly remunerated officers
(b) Unissued ordinary shares of Central Petroleum Limited or interests under option at the date of this report are as follows:
Class
Issue Price
Exercise Price
Expiry Date
Number on issue
Unlisted employee options
Nil
$0.20
30 Jun 2023
17,221,046
(c) No shares were issued by Central Petroleum Limited during or since the end of the year on the exercise of options.
ENVIRONMENTAL REGULATION
The Consolidated Entity is subject to significant environmental regulation.
The Consolidated Entity aims to ensure the appropriate standard of environmental care is achieved and, in doing so, that it is aware of and
is in compliance with all environmental legislation. Audit of compliance with the environmental conditions outlined in applicable
Environmental Management Plans over the course of the year identified over 99% compliance.
INSURANCE OF DIRECTORS AND OFFICERS
During the financial year, the Group paid premiums to insure Directors and officers of the Group. The contracts include a prohibition on
disclosure of the premium paid and nature of the liabilities covered under the policy.
A copy of the Auditor’s Independence Declaration as required under section 307C of the Corporations Act 2001 is set out on page 49.
AUDITOR’S INDEPENDENCE
ROUNDING OF AMOUNTS
The company is of a kind referred to in ASIC Legislative Instrument 2016/191, relating to the ‘rounding off’ of amounts in the directors’
report. Amounts in the directors’ report have been rounded off in accordance with the instrument to the nearest thousand dollars, or in
certain cases, to the nearest dollar.
30
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
31
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2022
Mr Troy Harry
Non-executive Director
Mr Harry was appointed as a director on 1 September 2022. He is a professional investor with interests in many ASX
listed companies, as well as private businesses and property. He formerly had a career in stockbroking and funds
management and was the founder of Trojan Investment Management Pty Ltd.
Troy is currently a director of numerous private entities and of The MND and Me Foundation Limited. He has not held
any other ASX directorships in the last 3 years.
Through his associated entities, Troy is a substantial shareholder in Central Petroleum Limited.
Ms Katherine Hirschfeld AM BE(Chem) UQ, HonFIEAust, FTSE, FIChemE, FAICD
Independent Non-executive Director
Ms Hirschfeld was appointed as a director on 7 December 2018 and is a highly regarded non-executive director, having
served on company boards listed on the ASX, NZX and NYSE, as well as government and private company boards. She is
currently the Chair of Powerlink and a board member of Spark Infrastructure RE Limited, its subsidiaries and related
entities (which includes the Boards of SA Power Networks and Victoria Power Networks (Powercor and CityPower)).
Ms Hirschfeld has also been a board member and President of UN Women National Committee Australia and non-
executive director of Energy Queensland, Tox Free Solutions, InterOil Corporation, Broadspectrum, Snowy Hydro and
Queensland Urban Utilities.
and Turkey.
Ms Hirschfeld was recognised in the AFR/Westpac 100 Women of Influence 2015, by Engineers Australia as one of
Australia’s Top 100 Most Influential Engineers 2015 and as an Honorary Fellow in 2014. She is a member of Chief
Executive Women and a Fellow of the Australian Institute of Company Directors and the Academy of Engineering and
Technology. She is also an executive mentor/coach with Merryck & Co.
In 2019 Ms Hirschfeld was appointed a Member of the Order of Australia (AM) for significant service to engineering, to
women, and to business.
Dr Agu Kantsler BSc (Hons), PhD, GAICD, FTSE
Independent Non-executive Director
Dr Kantsler has been a director of Central Petroleum Limited since 15 June 2020 and is one of Australia’s most
respected and experienced petroleum exploration executives, having led Woodside Petroleum’s world-wide
exploration, business development and geotechnical activities as Executive Vice President Exploration and New
Ventures from 1995 to 2009.
Prior to joining Woodside, Dr Kantsler worked for Shell in various international locations and has served as Director and
Chairman of the Australian Petroleum Production & Exploration Association (APPEA).
Dr Kantsler is Managing Director of Transform Exploration Pty Ltd, a former Director or Oil Search Limited and a former
President of the Chamber of Commerce and Industry WA.
COMPANY SECRETARY
Mr Daniel White LLB, BCom, LLM
Mr White is an experienced oil and gas lawyer in corporate finance transactions, mergers and acquisitions, equity and
debt capital raisings, joint venture, farmout and partnering arrangements and dispute resolution. He has previously
held senior international based positions with Kuwait Energy Company and Clough Limited.
INFORMATION ON DIRECTORS (CONTINUED)
DIRECTORS’ MEETINGS
The numbers of meetings of the Company’s board of directors and of each board committee held during the financial year, and the
numbers of meetings attended by each Director were:
Director
Stuart Baker
Leon Devaney
Stephen Gardiner3
Katherine Hirschfeld AM
Agu Kantsler
Michael McCormack
Full Meeting of
Directors
Audit & Financial Risk
Committee
Risk & Sustainability
Committee
Remuneration &
Nominations Committee
Eligible1
Attended
Eligible1
Attended2
Eligible1
Attended2
Eligible1
Attended2
8
8
8
8
8
8
8
8
8
8
8
8
4
—
4
4
—
4
4
4
4
4
4
4
—
—
5
5
5
5
5
5
5
5
5
5
5
—
—
—
5
5
5
5
5
5
5
5
1 Number of meetings held during the time the director held office or was a member of the committee during the year.
2 The number of meetings attended includes those attended by invitation.
3 Stephen Gardiner was appointed 1 July 2021.
SHARES UNDER OPTION
(a) There were no options granted during or since the end of the financial year to directors and the five most highly remunerated officers
of the Company.
Previously she had leadership roles with BP in oil refining, logistics, exploration and production located in Australia, UK
(b) Unissued ordinary shares of Central Petroleum Limited or interests under option at the date of this report are as follows:
Class
Issue Price
Exercise Price
Expiry Date
Number on issue
Unlisted employee options
Nil
$0.20
30 Jun 2023
17,221,046
(c) No shares were issued by Central Petroleum Limited during or since the end of the year on the exercise of options.
ENVIRONMENTAL REGULATION
The Consolidated Entity is subject to significant environmental regulation.
The Consolidated Entity aims to ensure the appropriate standard of environmental care is achieved and, in doing so, that it is aware of and
is in compliance with all environmental legislation. Audit of compliance with the environmental conditions outlined in applicable
Environmental Management Plans over the course of the year identified over 99% compliance.
INSURANCE OF DIRECTORS AND OFFICERS
During the financial year, the Group paid premiums to insure Directors and officers of the Group. The contracts include a prohibition on
disclosure of the premium paid and nature of the liabilities covered under the policy.
AUDITOR’S INDEPENDENCE
A copy of the Auditor’s Independence Declaration as required under section 307C of the Corporations Act 2001 is set out on page 49.
ROUNDING OF AMOUNTS
The company is of a kind referred to in ASIC Legislative Instrument 2016/191, relating to the ‘rounding off’ of amounts in the directors’
report. Amounts in the directors’ report have been rounded off in accordance with the instrument to the nearest thousand dollars, or in
certain cases, to the nearest dollar.
30
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
31
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2022
NON-AUDIT SERVICES
During the year the Company engaged the auditor, PricewaterhouseCoopers (PwC), on assignments additional to their statutory audit
duties where the auditor’s expertise and experience with the Company and/or the Consolidated Entity was important.
Details of amounts paid or payable to the auditor (PwC) for non-audit services provided during the year are set out below.
The Board of Directors is satisfied that the provision of the non-audit services is compatible with the general standard of independence for
auditors imposed by the Corporations Act 2001. The Directors are satisfied that the provision of non-audit services by the auditor, as set
out below, did not compromise the auditor independence requirements of the Corporations Act 2001 and did not compromise the general
principles relating to auditor independence in accordance with APES 110 Code of Ethics for Professional Accountants set by the Accounting
Professional and Ethical Standards Board.
PwC Australian firm:
(i)
Taxation services
Income tax compliance
Other tax related services
Total remuneration from non-audit services
Consolidated
2022
$
9,588
10,579
20,167
2021
$
9,129
26,864
35,993
32
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
EXECUTIVE SUMMARY – REMUNERATION
Dear Shareholders,
Executive incentives
In contrast to the COVID-interrupted recent years, the year just
gone has seen a raft of activity across our portfolio. We have
completed drilling and commissioning two new production wells
at Mereenie, drilled and commenced testing two pilot wells at
our Range CSG project and are drilling at Palm Valley. The
completion of the sale of 50% of our operating assets to New
Zealand Oil & Gas and Cue Energy Resources realised a
$36 million profit and released significant capital to retire debt
and fund our growth activity.
Commercially, the introduction of a new joint venture partner in
three exploration tenements has provided the catalyst for a
three well sub-salt exploration program starting next year,
targeting helium, hydrogen and hydrocarbons. We secured
transportation arrangements which enabled us to supply gas
into volatile east coast energy markets, boosting revenues from
our smaller production base.
These have been achieved against the background of labour
shortages, supply chain disruptions and rising costs. Last year I
identified that attracting and retaining key personnel to progress
these activities was a key priority, and it remains so.
Competition for experienced personnel remains strong, with
buoyant oil and gas markets driving increased activity across the
industry at a time when access to skilled labour remains
restricted.
To address these changing market dynamics and to re-weight
incentives to reward short-term performance on our
transformational growth programs, we tailored our FY2022
remuneration structure to provide targeted performance
incentives across the Company. The key components are
summarised below.
Fixed remuneration
Following the freeze in fixed remuneration for FY2021,
remuneration from July 2021 increased by approximately 2%
along with the 0.5% increase in compulsory superannuation
contributions. With rising inflation pressures and to remain
competitive, average salaries will rise by approximately 4.5%
from July 2022 plus the 0.5% increase in superannuation
contributions.
Short-term incentives
In FY2022, executives did not participate in the Short Term
Incentive Plan (STIP). All other staff participated in the STIP
which targeted near-term performance in lieu of participation in
equity-based plans of previous years. Achievement of short term
responsibility.
The Company was successful in exceeding its revenue targets
and controlling production and corporate costs, but slow
progress on the Range gas project and slippages and cost
overruns in the exploration drilling program detracted from
overall performance. As a result, personnel were entitled to an
average 62.75% of their maximum STIP incentive for the year.
For FY2022 our executive team switched to a new incentive
program that integrates short and long-term components. The
CEO can earn up to 120% of his fixed remuneration, while other
executives can be awarded up to 80%. Performance was
measured against the same corporate KPI targets set for the
STIP. Of the maximum available in FY2022, 62.5% was awarded,
with one-third to be paid this year and the balance converting
into share rights vesting over the next three years.
LTIP
The LTIP which has been in place for several years has been
discontinued, replaced by the STIP and executive plan outlined
above for FY2022.
In previous years, executives and senior employees participated
in the Employee Rights Plan / Long Term Incentive Plan (LTIP)
that was designed to align management’s interests directly with
those of shareholders through Total Shareholder Return (TSR)
hurdles. The LTIP was measured over a three year performance
period and targeted half of its reward outcomes to Central’s
shares outperforming those of its peer group (Relative TSR) and
half to Absolute TSR. Absolute TSR must exceed 10% per annum
for three years to achieve any part of this second element and
25% per annum for three years to receive the whole of this
element.
As the legacy LTIP runs-off, performance against the relevant
targets will be measured annually. The LTIP’s Absolute TSR
performance for the three years from 1 July 2019 to 30 June
2022 failed to achieve the minimum growth hurdle of 10% pa.
Whilst disappointing, Central’s share price performance over
this period was relatively strong when compared to our peers
within the sector. The Relative TSR placed Central at the 86th
percentile compared to its peers, resulting in 43% of rights
vesting for this three year performance period. The Board has
discretion to retest performance of these hurdles at
31 December 2022.
For the first time, Directors sacrificed a portion of their fees to
acquire share rights to increase their alignment with our
shareholders.
Consistent with previous years, we have included a Realised
Remuneration table (refer Table 1 in section I of the
Remuneration Report) to assist readers of this report to
understand the actual remuneration which the senior executives
have received this year – something which is not always clear
with the statutory reporting requirements.
Michael (Mick) McCormack
Remuneration and Nominations Committee Chair
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
33
incentives depends on achieving personal and corporate
With the transition from legacy incentive plans to the new
objectives over the year, providing an opportunity to earn from
structure, the remuneration report appears complicated, but we
10% to 30% of base remuneration, depending on role and
are confident the remuneration structure introduced this year
will meet the expectations of our shareholders and ensure that
our team is focussed on extracting the best value from our
portfolio of assets.
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2022
NON-AUDIT SERVICES
During the year the Company engaged the auditor, PricewaterhouseCoopers (PwC), on assignments additional to their statutory audit
duties where the auditor’s expertise and experience with the Company and/or the Consolidated Entity was important.
Details of amounts paid or payable to the auditor (PwC) for non-audit services provided during the year are set out below.
The Board of Directors is satisfied that the provision of the non-audit services is compatible with the general standard of independence for
auditors imposed by the Corporations Act 2001. The Directors are satisfied that the provision of non-audit services by the auditor, as set
out below, did not compromise the auditor independence requirements of the Corporations Act 2001 and did not compromise the general
principles relating to auditor independence in accordance with APES 110 Code of Ethics for Professional Accountants set by the Accounting
Professional and Ethical Standards Board.
PwC Australian firm:
(i)
Taxation services
Income tax compliance
Other tax related services
Total remuneration from non-audit services
Consolidated
2022
$
9,588
10,579
20,167
2021
$
9,129
26,864
35,993
32
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
EXECUTIVE SUMMARY – REMUNERATION
Dear Shareholders,
Executive incentives
In contrast to the COVID-interrupted recent years, the year just
gone has seen a raft of activity across our portfolio. We have
completed drilling and commissioning two new production wells
at Mereenie, drilled and commenced testing two pilot wells at
our Range CSG project and are drilling at Palm Valley. The
completion of the sale of 50% of our operating assets to New
Zealand Oil & Gas and Cue Energy Resources realised a
$36 million profit and released significant capital to retire debt
and fund our growth activity.
Commercially, the introduction of a new joint venture partner in
three exploration tenements has provided the catalyst for a
three well sub-salt exploration program starting next year,
targeting helium, hydrogen and hydrocarbons. We secured
transportation arrangements which enabled us to supply gas
into volatile east coast energy markets, boosting revenues from
our smaller production base.
These have been achieved against the background of labour
shortages, supply chain disruptions and rising costs. Last year I
identified that attracting and retaining key personnel to progress
these activities was a key priority, and it remains so.
Competition for experienced personnel remains strong, with
buoyant oil and gas markets driving increased activity across the
industry at a time when access to skilled labour remains
restricted.
To address these changing market dynamics and to re-weight
incentives to reward short-term performance on our
transformational growth programs, we tailored our FY2022
remuneration structure to provide targeted performance
incentives across the Company. The key components are
summarised below.
Fixed remuneration
Following the freeze in fixed remuneration for FY2021,
remuneration from July 2021 increased by approximately 2%
along with the 0.5% increase in compulsory superannuation
contributions. With rising inflation pressures and to remain
competitive, average salaries will rise by approximately 4.5%
from July 2022 plus the 0.5% increase in superannuation
contributions.
Short-term incentives
In FY2022, executives did not participate in the Short Term
Incentive Plan (STIP). All other staff participated in the STIP
which targeted near-term performance in lieu of participation in
equity-based plans of previous years. Achievement of short term
incentives depends on achieving personal and corporate
objectives over the year, providing an opportunity to earn from
10% to 30% of base remuneration, depending on role and
responsibility.
The Company was successful in exceeding its revenue targets
and controlling production and corporate costs, but slow
progress on the Range gas project and slippages and cost
overruns in the exploration drilling program detracted from
overall performance. As a result, personnel were entitled to an
average 62.75% of their maximum STIP incentive for the year.
For FY2022 our executive team switched to a new incentive
program that integrates short and long-term components. The
CEO can earn up to 120% of his fixed remuneration, while other
executives can be awarded up to 80%. Performance was
measured against the same corporate KPI targets set for the
STIP. Of the maximum available in FY2022, 62.5% was awarded,
with one-third to be paid this year and the balance converting
into share rights vesting over the next three years.
LTIP
The LTIP which has been in place for several years has been
discontinued, replaced by the STIP and executive plan outlined
above for FY2022.
In previous years, executives and senior employees participated
in the Employee Rights Plan / Long Term Incentive Plan (LTIP)
that was designed to align management’s interests directly with
those of shareholders through Total Shareholder Return (TSR)
hurdles. The LTIP was measured over a three year performance
period and targeted half of its reward outcomes to Central’s
shares outperforming those of its peer group (Relative TSR) and
half to Absolute TSR. Absolute TSR must exceed 10% per annum
for three years to achieve any part of this second element and
25% per annum for three years to receive the whole of this
element.
As the legacy LTIP runs-off, performance against the relevant
targets will be measured annually. The LTIP’s Absolute TSR
performance for the three years from 1 July 2019 to 30 June
2022 failed to achieve the minimum growth hurdle of 10% pa.
Whilst disappointing, Central’s share price performance over
this period was relatively strong when compared to our peers
within the sector. The Relative TSR placed Central at the 86th
percentile compared to its peers, resulting in 43% of rights
vesting for this three year performance period. The Board has
discretion to retest performance of these hurdles at
31 December 2022.
For the first time, Directors sacrificed a portion of their fees to
acquire share rights to increase their alignment with our
shareholders.
Consistent with previous years, we have included a Realised
Remuneration table (refer Table 1 in section I of the
Remuneration Report) to assist readers of this report to
understand the actual remuneration which the senior executives
have received this year – something which is not always clear
with the statutory reporting requirements.
With the transition from legacy incentive plans to the new
structure, the remuneration report appears complicated, but we
are confident the remuneration structure introduced this year
will meet the expectations of our shareholders and ensure that
our team is focussed on extracting the best value from our
portfolio of assets.
Michael (Mick) McCormack
Remuneration and Nominations Committee Chair
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
33
REMUNERATION REPORT
(AUDITED)
This Remuneration Report for the year ended 30 June 2022 (FY2022) outlines the remuneration arrangements of the Group in accordance
with the requirements of the Corporations Act 2001 (Cth), as amended (the Act). This information has been audited as required by section
308(3C) of the Act.
B. Remuneration Overview (continued)
Financial Year 2022
Summary of fixed and variable remuneration outcomes
The Remuneration Report is presented under the following sections:
A
B
C
D
E
F
G
H
I
J
K
L
Directors and Key Management Personnel (KMP)
Remuneration Overview
Remuneration Policy
Remuneration Consultants
Long Term Incentive Plan – Employee Rights Plan (LTIP)
Executive Share Option Plan (ESOP)
Executive Incentive Plan (EIP)
Short Term Incentive Plan (STIP)
Realised Remuneration
Remuneration Details – Statutory Tables
Executive Service Agreements
Non-Executive Director Fee Arrangements
A. Directors and Key Management Personnel (KMP)
The Directors and key management personnel of the Consolidated Entity during the year and up to signing date of the annual report were:
Vesting of Share Rights
previously granted under
the Long Term Incentive
Plan (LTIP)
The vesting rate for Share Rights issued under the Long Term Incentive Plan for the three year period
ending 30 June 2022 was 43%. This may, at the Board’s discretion, be eligible for retesting at 31 December
2022. Refer Section E of this report.
Directors
Mr Michael (Mick) McCormack
Mr Leon Devaney
Mr Stuart Baker
Mr Stephen Gardiner
Mr Troy Harry
Ms Katherine Hirschfeld AM
Dr Agu Kantsler
Independent Non-executive Chair
Managing Director and Chief Executive Officer
Independent Non-executive Director (resigned 30 August 2022)
Independent Non-executive Director
Non-executive Director (commenced 1 September 2022)
Independent Non-executive Director
Independent Non-executive Director
Other Key Management Personnel
Mr Ross Evans
Mr Damian Galvin
Dr Duncan Lockhart
Mr Jonathan Snape
Mr Daniel White
Chief Operations Officer
Chief Financial Officer
General Manager Exploration (resigned 31 August 2022)
Chief Commercial Officer
Group General Counsel and Company Secretary
B. Remuneration Overview
Central’s remuneration strategy is designed to attract, motivate and retain high performing individuals and is linked to the Group’s
objectives to build long-term shareholder value. In doing so, Central adopts a pay for performance culture which is balanced by a fair and
equitable approach to the retention and motivation of its team. The current remuneration strategy incorporates the following features:
a.
b.
c.
d.
Linking internal strategies to improved shareholder value through achievement of appropriate KPIs.
Company-wide performance incentives to drive high performance.
Providing key executives with incentives which provide rewards for achievement of annual KPI targets, payable through a
combination of cash and deferred equity to provide longer-term alignment with shareholders.
Adjusting to remuneration best practice and movements in relevant labour markets.
Salary increases in FY2022
A 2% pay rise applied to eligible employees for FY2022 and compulsory superannuation contributions
increased from 9.5% to 10%. As at 1 July 2022, a 4.5% pay rise will apply to eligible employees for FY2023.
In addition, employees will benefit from the statutory increase in compulsory superannuation contributions
from 10% to 10.5%.
Short Term Incentive Plan
Achievement of Company-wide corporate and individual KPIs resulted in payment of an average 62.75% of
the maximum STIP to eligible employees. Refer Section H of this report.
Executive Incentive Plan
Achievement of Company-wide corporate KPIs resulted in an award of 62.5% with 1/3 of the awarded value
being payable as cash (or equity) and 2/3 being Share Rights to vest progressively over the next 3 years.
(STIP)
(EIP)
Executive Share Option
Share Options granted to eligible executives in 2019 as long term incentives for FY2020, FY2021 and FY2022
Plan (ESOP)
vested on 1 July 2022. The options have an exercise price of $0.20 and expire on 30 June 2023. Refer
Refer Section G of this report.
Section F of this report.
C. Remuneration Policy
The remuneration policy of the Company is to pay its directors and executives amounts in line with employment market conditions
relevant to the oil and gas industry whilst reflecting Central’s specific circumstances. The Company’s remuneration practices and, in
particular, its short term and long term incentive plans are focussed on creating strong linkages between shareholder value as measured by
shareholder returns and executive remuneration. Consequently, the major component of executive incentives has been the Employee
Rights Plan/Long Term Incentive Plan (LTIP), Executive Share Option Plan (ESOP) and Executive Incentive Plan (EIP) rather than the Short
Term Incentive Plan (STIP).
From FY2022, executives participate in a revised incentive plan that combines both short term annual KPIs and a longer-term, deferred
equity-based component (refer Section G below).
For periods up to and ending on 30 June 2022, the remuneration of directors and executives consisted of the following key elements:
Non-executive directors:
1.
Fees including statutory superannuation;
2. Up to 25% sacrifice of FY2022 base fees (inclusive of superannuation but excluding committee fees) in order to receive an equivalent
value in the form of Share Rights issued under the Company’s Employee Rights Plan; and
3. No participation in short or long term incentive schemes.
Executives, including executive directors:
1.
2.
3.
Annual salary and non-monetary benefits including statutory superannuation;
Participation in the Executive Incentive Plan (EIP), vesting over a 4 year period (from FY2022); and
Participation in a Long Term Incentive Plan (LTIPs or ESOPs), vesting over a 3 year period (no new grants after FY2021).
The balance of fixed and maximum at risk remuneration for executives for FY2022 is summarised as follows:
CEO
45% fixed remuneration
18% at risk
36 % at risk (EIP Service Rights)
Other Executives
56% fixed remuneration
15% at risk
30% at risk (EIP Service
Rights)
Salary
EIP short term
EIP over three years
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CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
35
REMUNERATION REPORT
(AUDITED)
308(3C) of the Act.
The Remuneration Report is presented under the following sections:
Directors and Key Management Personnel (KMP)
Remuneration Overview
Remuneration Policy
Remuneration Consultants
Long Term Incentive Plan – Employee Rights Plan (LTIP)
Executive Share Option Plan (ESOP)
Executive Incentive Plan (EIP)
Short Term Incentive Plan (STIP)
Realised Remuneration
Remuneration Details – Statutory Tables
Executive Service Agreements
Non-Executive Director Fee Arrangements
A
B
C
D
E
F
G
H
I
J
K
L
A. Directors and Key Management Personnel (KMP)
The Directors and key management personnel of the Consolidated Entity during the year and up to signing date of the annual report were:
Directors
Mr Leon Devaney
Mr Stuart Baker
Mr Michael (Mick) McCormack
Independent Non-executive Chair
Managing Director and Chief Executive Officer
Independent Non-executive Director (resigned 30 August 2022)
Mr Stephen Gardiner
Independent Non-executive Director
Mr Troy Harry
Non-executive Director (commenced 1 September 2022)
Ms Katherine Hirschfeld AM
Independent Non-executive Director
Dr Agu Kantsler
Independent Non-executive Director
Other Key Management Personnel
Mr Ross Evans
Mr Damian Galvin
Dr Duncan Lockhart
Mr Jonathan Snape
Mr Daniel White
Chief Operations Officer
Chief Financial Officer
General Manager Exploration (resigned 31 August 2022)
Chief Commercial Officer
Group General Counsel and Company Secretary
B. Remuneration Overview
Central’s remuneration strategy is designed to attract, motivate and retain high performing individuals and is linked to the Group’s
objectives to build long-term shareholder value. In doing so, Central adopts a pay for performance culture which is balanced by a fair and
equitable approach to the retention and motivation of its team. The current remuneration strategy incorporates the following features:
a.
b.
c.
Linking internal strategies to improved shareholder value through achievement of appropriate KPIs.
Company-wide performance incentives to drive high performance.
Providing key executives with incentives which provide rewards for achievement of annual KPI targets, payable through a
combination of cash and deferred equity to provide longer-term alignment with shareholders.
d.
Adjusting to remuneration best practice and movements in relevant labour markets.
This Remuneration Report for the year ended 30 June 2022 (FY2022) outlines the remuneration arrangements of the Group in accordance
with the requirements of the Corporations Act 2001 (Cth), as amended (the Act). This information has been audited as required by section
B. Remuneration Overview (continued)
Financial Year 2022
Summary of fixed and variable remuneration outcomes
Salary increases in FY2022
A 2% pay rise applied to eligible employees for FY2022 and compulsory superannuation contributions
increased from 9.5% to 10%. As at 1 July 2022, a 4.5% pay rise will apply to eligible employees for FY2023.
In addition, employees will benefit from the statutory increase in compulsory superannuation contributions
from 10% to 10.5%.
Short Term Incentive Plan
(STIP)
Achievement of Company-wide corporate and individual KPIs resulted in payment of an average 62.75% of
the maximum STIP to eligible employees. Refer Section H of this report.
Executive Incentive Plan
(EIP)
Achievement of Company-wide corporate KPIs resulted in an award of 62.5% with 1/3 of the awarded value
being payable as cash (or equity) and 2/3 being Share Rights to vest progressively over the next 3 years.
Refer Section G of this report.
Executive Share Option
Plan (ESOP)
Share Options granted to eligible executives in 2019 as long term incentives for FY2020, FY2021 and FY2022
vested on 1 July 2022. The options have an exercise price of $0.20 and expire on 30 June 2023. Refer
Section F of this report.
Vesting of Share Rights
previously granted under
the Long Term Incentive
Plan (LTIP)
The vesting rate for Share Rights issued under the Long Term Incentive Plan for the three year period
ending 30 June 2022 was 43%. This may, at the Board’s discretion, be eligible for retesting at 31 December
2022. Refer Section E of this report.
C. Remuneration Policy
The remuneration policy of the Company is to pay its directors and executives amounts in line with employment market conditions
relevant to the oil and gas industry whilst reflecting Central’s specific circumstances. The Company’s remuneration practices and, in
particular, its short term and long term incentive plans are focussed on creating strong linkages between shareholder value as measured by
shareholder returns and executive remuneration. Consequently, the major component of executive incentives has been the Employee
Rights Plan/Long Term Incentive Plan (LTIP), Executive Share Option Plan (ESOP) and Executive Incentive Plan (EIP) rather than the Short
Term Incentive Plan (STIP).
From FY2022, executives participate in a revised incentive plan that combines both short term annual KPIs and a longer-term, deferred
equity-based component (refer Section G below).
For periods up to and ending on 30 June 2022, the remuneration of directors and executives consisted of the following key elements:
Non-executive directors:
Fees including statutory superannuation;
1.
2. Up to 25% sacrifice of FY2022 base fees (inclusive of superannuation but excluding committee fees) in order to receive an equivalent
value in the form of Share Rights issued under the Company’s Employee Rights Plan; and
3. No participation in short or long term incentive schemes.
Executives, including executive directors:
1.
2.
3.
Annual salary and non-monetary benefits including statutory superannuation;
Participation in the Executive Incentive Plan (EIP), vesting over a 4 year period (from FY2022); and
Participation in a Long Term Incentive Plan (LTIPs or ESOPs), vesting over a 3 year period (no new grants after FY2021).
The balance of fixed and maximum at risk remuneration for executives for FY2022 is summarised as follows:
CEO
45% fixed remuneration
18% at risk
36 % at risk (EIP Service Rights)
Other Executives
56% fixed remuneration
15% at risk
30% at risk (EIP Service
Rights)
Salary
EIP short term
EIP over three years
34
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
35
REMUNERATION REPORT
(AUDITED)
C. Remuneration Policy (continued)
E. Long Term Incentive Plan – Employee Rights Plan (LTIP) (continued)
The following table summarises the key performance and shareholder wealth metrics in relation to the outcomes of the STIP, LTIP and EIP
over the last five years:
FY2022 Performance
FY2018
FY2019
FY2020
FY2021
FY2022
Financial performance
Operating revenue
Profit/(loss) after income tax
Underlying EBITDAX
Shareholder wealth
Share price at year end
Absolute TSR (3 years)
Relative TSR (3 years)
Incentive awarded
STIP
LTIP
EIP
$ million
$ million
$ million
$/share
% growth pa
Percentile rank
% of maximum
% of maximum
% of maximum
34.94
(14.08)
11.01
$0.130
5.7%
75th
33%
49.5%
N/a
59.36
(14.53)
22.19
$0.135
15.5%
88th
82%
75%
N/a
65.05
5.41
25.01
$0.081
(16.1%)
25th
67%
nil
N/a
59.83
0.25
26.09
$0.117
(9.1%)
57th
67%
31.5%
N/a
42.15
21.32
16.75
$0.110
(4.6%)
69th
62.75%
43%
62.5%
In the past five years, Central has recorded strong revenue and underlying EBITDAX results as expansion programs at the Company’s
Amadeus Basin oil and gas fields enabled increased production into new markets with the opening of the Northern Gas Pipeline in early
2019. In FY2022, the partial sale of the Company’s producing oil and gas assets was completed, recognising a $36.6 million profit on the
sale and providing funds to pay-down debt and fund new exploration and development activity. STIP awards since FY2019 have reflected
this success, paid as a combination of cash, equity and deferred equity over those years. The FY2022 STIP/EIP award reflected a strong
operating performance from the smaller asset base, with revenue and cost control exceeding stretch targets. The STIP/EIP award in FY2022
however, would have been higher, but for delays and cost overruns to the Company’s exploration and appraisal programs.
The LTIP awards over recent years have followed the Company’s 3 year share price performance, resulting in a relatively high award in
FY2019 as the share price reflected increasing production and announcement of the Range gas project. COVID-related market weakness
impacted the FY2020 award, with only participants in the $1,000 Exempt Plan LTIP receiving any value. Volatile equity and energy markets
in FY2021 and FY2022 have seen relatively little share price growth in absolute terms, but Central’s shares have performed relatively well
against those of its peers, resulting in a partial vesting of LTIPs for participants in those years.
D. Remuneration Consultants
The performance of the Company depends upon the quality of its directors and executives and the Company strives to attract, motivate
and retain highly qualified and skilled management. Salaries and directors’ fees are reviewed at least annually to ensure they remain
competitive with the market.
For each annual remuneration review cycle, the Remuneration Committee considers whether to appoint a remuneration consultant and, if
so, their scope of work.
No remuneration consultants were engaged for the July 2021 review of remuneration. Guerdon Associates were engaged to provide
market information relating to Non-executive Director fee increases over the prior two years and upcoming 12-months (on account that
fees for the Company’s Directors have not increased since 2017).
E. Long Term Incentive Plan – Employee Rights Plan (LTIP)
The LTIP has been a major component of executive incentives and, in developing the Employee Rights Plan, the Board focused on creating
strong linkages between shareholder value as measured by shareholder returns and executive remuneration. Consequently, vesting
conditions have been weighted equally between relative shareholder return and absolute shareholder return over a three-year period,
aligning executive’s reward with share performance against peer companies and also with absolute share price growth.
Key terms and vesting conditions
The Company’s LTIP was last approved by shareholders in November 2018 to incentivise eligible employees (Non-Executive Directors are
not eligible to participate in the LTIP).
The maximum number of performance rights vested in any year is determined by measuring Central’s share price performance compared
to a peer group of companies (relative measure) and its absolute share price movement over a three-year cycle.
The following table details the percentage of Share Rights in respect of the three-year performance period ending 30 June 2022 which will
vest (Vesting Percentage) as determined by the performance conditions, based on the 20-day VWAP prior to 30 June 2022 of $0.1183. The
benchmark share price at the start of the performance period was $0.1361:
Hurdle
Definition
Hurdle Banding
Absolute TSR1 growth
Company's absolute TSR calculated as at
Company’s Absolute TSR
Share Rights
(50% weighting)
vesting date. This looks to align eligible
employees’ rewards to shareholder
superior returns
Vesting
Percentage
Result for Plan
Year Vesting
30 June 2022
over 3 years
25% pa plus
20% to <25% pa
15% to <20% pa
10% to <15% pa
Below 10% pa
Vesting
100%
75%
50%
25%
0%
Relative TSR – E&P2
(50% weighting)
Company's TSR relative to a specific group
of exploration and production companies3
(determined by the Board within its
discretion) calculated as at vesting date
Company’s Relative TSR
76th percentile and above
Share Rights
Vesting
100%
From 51st to 75th percentile
50% to 99%
(86%)
Below 51st percentile
0%
1 Total shareholder return (i.e. growth in share price plus dividends reinvested).
2 Exploration and Production.
3 The peer group of companies for the three-year performance period ended 30 June 2022 is: Armour Energy Limited, Blue Energy Limited, Buru Energy Limited,
Carnarvon Petroleum Limited, Cooper Energy Limited, Comet Ridge Limited, Empire Energy Group Limited, FAR Limited, Galilee Energy Limited, Horizon Oil Limited,
Icon Energy Limited, State Gas Limited, Strike Energy Limited, Triangle Energy Global Limited, Vintage Energy and 3D Oil Limited.
For the purposes of determining the number of Share Rights to vest, the Company’s absolute TSR and relative TSR are calculated as at the
end of the performance period. The Vesting Percentage for each is determined by reference to the hurdle bandings set out in the above
tables. The Share Rights for each applicable hurdle are then multiplied by the Vesting Percentage achieved for that hurdle to determine the
total number of Share Rights which vest on the vesting date. Vested Share Rights may then be exercised in accordance with the Employee
Rights Plan Rules. Each vested Share Right can be exercised at the rate of one Share Right for one Ordinary Share in the Company.
Employees must be employed by the Company at the end of the performance period in order for the Share Rights to vest. The maximum
number of Share Rights that an employee was granted is a function of the employee’s Total Fixed Remuneration (TFR) and the 20 trading
days daily volume weighted average sale price of company shares sold on the ASX ending on the trading day prior to the start of the
If the Company is subject to a Change of Control Event, all unvested Share Rights will immediately vest at 100%, with any performance
Details of the LTIP Plan’s key terms can be viewed on the Company’s website at www.centralpetroleum.com.au/careers/why-work-for-
performance period.
criteria being waived.
central.
Participation
Up until FY2021, this LTIP has provided coverage for various levels of eligible employees which include:
a.
The Managing Director who is principally responsible for achievement of Central’s strategy:
Up until FY2019 received a LTIP percentage of up to 50% of TFR, subject to shareholder approval; and
From FY2020 to FY2021 participated in the ESOP (refer Section F of this report);
b.
The Executive Management Team (EMT) received a LTIP percentage up to 30% of their TFR until FY2019, after which they
participated in only the ESOP in FY2020 and FY2021 (one EMT member did not participate in the ESOP and continued in the LTIP
i)
ii)
until FY2021);
36
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
37
C. Remuneration Policy (continued)
E. Long Term Incentive Plan – Employee Rights Plan (LTIP) (continued)
The following table summarises the key performance and shareholder wealth metrics in relation to the outcomes of the STIP, LTIP and EIP
FY2022 Performance
The following table details the percentage of Share Rights in respect of the three-year performance period ending 30 June 2022 which will
vest (Vesting Percentage) as determined by the performance conditions, based on the 20-day VWAP prior to 30 June 2022 of $0.1183. The
benchmark share price at the start of the performance period was $0.1361:
Hurdle
Definition
Hurdle Banding
Vesting
Percentage
Result for Plan
Year Vesting
30 June 2022
Absolute TSR1 growth
(50% weighting)
Company's absolute TSR calculated as at
vesting date. This looks to align eligible
employees’ rewards to shareholder
superior returns
Relative TSR – E&P2
(50% weighting)
Company's TSR relative to a specific group
of exploration and production companies3
(determined by the Board within its
discretion) calculated as at vesting date
Company’s Absolute TSR
over 3 years
Share Rights
Vesting
25% pa plus
20% to <25% pa
15% to <20% pa
10% to <15% pa
Below 10% pa
100%
75%
50%
25%
0%
Company’s Relative TSR
76th percentile and above
Share Rights
Vesting
100%
From 51st to 75th percentile
50% to 99%
(86%)
Below 51st percentile
0%
1 Total shareholder return (i.e. growth in share price plus dividends reinvested).
2 Exploration and Production.
3 The peer group of companies for the three-year performance period ended 30 June 2022 is: Armour Energy Limited, Blue Energy Limited, Buru Energy Limited,
Carnarvon Petroleum Limited, Cooper Energy Limited, Comet Ridge Limited, Empire Energy Group Limited, FAR Limited, Galilee Energy Limited, Horizon Oil Limited,
Icon Energy Limited, State Gas Limited, Strike Energy Limited, Triangle Energy Global Limited, Vintage Energy and 3D Oil Limited.
For the purposes of determining the number of Share Rights to vest, the Company’s absolute TSR and relative TSR are calculated as at the
end of the performance period. The Vesting Percentage for each is determined by reference to the hurdle bandings set out in the above
tables. The Share Rights for each applicable hurdle are then multiplied by the Vesting Percentage achieved for that hurdle to determine the
total number of Share Rights which vest on the vesting date. Vested Share Rights may then be exercised in accordance with the Employee
Rights Plan Rules. Each vested Share Right can be exercised at the rate of one Share Right for one Ordinary Share in the Company.
Employees must be employed by the Company at the end of the performance period in order for the Share Rights to vest. The maximum
number of Share Rights that an employee was granted is a function of the employee’s Total Fixed Remuneration (TFR) and the 20 trading
days daily volume weighted average sale price of company shares sold on the ASX ending on the trading day prior to the start of the
performance period.
If the Company is subject to a Change of Control Event, all unvested Share Rights will immediately vest at 100%, with any performance
criteria being waived.
Details of the LTIP Plan’s key terms can be viewed on the Company’s website at www.centralpetroleum.com.au/careers/why-work-for-
central.
Participation
Up until FY2021, this LTIP has provided coverage for various levels of eligible employees which include:
a.
The Managing Director who is principally responsible for achievement of Central’s strategy:
i)
ii)
Up until FY2019 received a LTIP percentage of up to 50% of TFR, subject to shareholder approval; and
From FY2020 to FY2021 participated in the ESOP (refer Section F of this report);
b.
The Executive Management Team (EMT) received a LTIP percentage up to 30% of their TFR until FY2019, after which they
participated in only the ESOP in FY2020 and FY2021 (one EMT member did not participate in the ESOP and continued in the LTIP
until FY2021);
REMUNERATION REPORT
(AUDITED)
over the last five years:
Financial performance
Operating revenue
Profit/(loss) after income tax
Underlying EBITDAX
Shareholder wealth
Share price at year end
Absolute TSR (3 years)
Relative TSR (3 years)
Incentive awarded
STIP
LTIP
EIP
FY2018
FY2019
FY2020
FY2021
FY2022
$ million
$ million
$ million
34.94
(14.08)
11.01
$/share
$0.130
% growth pa
Percentile rank
% of maximum
% of maximum
% of maximum
5.7%
75th
33%
49.5%
N/a
59.36
(14.53)
22.19
$0.135
15.5%
88th
82%
75%
N/a
65.05
5.41
25.01
$0.081
(16.1%)
25th
67%
nil
N/a
59.83
0.25
26.09
$0.117
(9.1%)
57th
67%
31.5%
N/a
42.15
21.32
16.75
$0.110
(4.6%)
69th
62.75%
43%
62.5%
In the past five years, Central has recorded strong revenue and underlying EBITDAX results as expansion programs at the Company’s
Amadeus Basin oil and gas fields enabled increased production into new markets with the opening of the Northern Gas Pipeline in early
2019. In FY2022, the partial sale of the Company’s producing oil and gas assets was completed, recognising a $36.6 million profit on the
sale and providing funds to pay-down debt and fund new exploration and development activity. STIP awards since FY2019 have reflected
this success, paid as a combination of cash, equity and deferred equity over those years. The FY2022 STIP/EIP award reflected a strong
operating performance from the smaller asset base, with revenue and cost control exceeding stretch targets. The STIP/EIP award in FY2022
however, would have been higher, but for delays and cost overruns to the Company’s exploration and appraisal programs.
The LTIP awards over recent years have followed the Company’s 3 year share price performance, resulting in a relatively high award in
FY2019 as the share price reflected increasing production and announcement of the Range gas project. COVID-related market weakness
impacted the FY2020 award, with only participants in the $1,000 Exempt Plan LTIP receiving any value. Volatile equity and energy markets
in FY2021 and FY2022 have seen relatively little share price growth in absolute terms, but Central’s shares have performed relatively well
against those of its peers, resulting in a partial vesting of LTIPs for participants in those years.
D. Remuneration Consultants
The performance of the Company depends upon the quality of its directors and executives and the Company strives to attract, motivate
and retain highly qualified and skilled management. Salaries and directors’ fees are reviewed at least annually to ensure they remain
competitive with the market.
so, their scope of work.
For each annual remuneration review cycle, the Remuneration Committee considers whether to appoint a remuneration consultant and, if
No remuneration consultants were engaged for the July 2021 review of remuneration. Guerdon Associates were engaged to provide
market information relating to Non-executive Director fee increases over the prior two years and upcoming 12-months (on account that
fees for the Company’s Directors have not increased since 2017).
E. Long Term Incentive Plan – Employee Rights Plan (LTIP)
The LTIP has been a major component of executive incentives and, in developing the Employee Rights Plan, the Board focused on creating
strong linkages between shareholder value as measured by shareholder returns and executive remuneration. Consequently, vesting
conditions have been weighted equally between relative shareholder return and absolute shareholder return over a three-year period,
aligning executive’s reward with share performance against peer companies and also with absolute share price growth.
Key terms and vesting conditions
not eligible to participate in the LTIP).
The Company’s LTIP was last approved by shareholders in November 2018 to incentivise eligible employees (Non-Executive Directors are
The maximum number of performance rights vested in any year is determined by measuring Central’s share price performance compared
to a peer group of companies (relative measure) and its absolute share price movement over a three-year cycle.
36
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
37
REMUNERATION REPORT
(AUDITED)
E. Long Term Incentive Plan – Employee Rights Plan (LTIP) (continued)
G. Executive Incentive Plan (EIP)
c.
d.
e.
Eligible employees who are in roles which influence and drive the strategic direction of the Company’s business or who are senior
managers with responsibility for one or more defined functions, departments or outcomes have been eligible to receive a
maximum LTIP percentage of 20% or 30% of TFR until FY2021;
Eligible employees who are in roles which are focused on the key drivers of the operational parts of the Company’s business have
received a maximum LTIP percentage of 10% of TFR up until FY2021; and
All other eligible employees are integral to the success of the Company obtaining its goals and objectives and may participate in
the Central Petroleum $1,000 Exempt Plan.
Conditions of the Central Petroleum $1,000 Exempt Plan include:
1.
Share Rights can only be dealt with upon vesting at the end of the three-year service period; and
2. No performance conditions apply.
In 2021, Central conducted an external review of the effectiveness of the LTIP in providing a relevant incentive to all levels of personnel.
The review took into account many factors, including the history of rewards under the scheme, taxation implications for employees, near
and longer-term drivers of shareholder value and alternative incentive scheme structures used by peers and the broader market. As a
result of the review:
i)
ii)
iii)
No further LTIPs have been granted under the existing LTIP structure described above from 1 July 2021;
The Managing Director (subject to shareholder approval) and EMT are eligible to participate in an Executive Incentive Plan (EIP)
from FY2022 (refer Section G of this report); and
Incentive for employees in categories c, d and e above will be re-weighted to a single STIP opportunity (refer Section H of this
report) and be eligible to participate in the Central Petroleum $1,000 Exempt Plan.
F. Long Term Incentive Plan – Executive Share Option Plan (ESOP)
Participation
On 7 November 2019, shareholders approved the establishment of an ESOP for certain key executives. The ESOP replaced the previous LTIP
for participating executives and any Share Options granted under the ESOP replaced the Share Rights that would otherwise have been
granted in FY2020, FY2021 and FY2022 under the LTIP.
Key terms and vesting conditions
Each Share Option entitles the participant to subscribe for one Share upon exercise of the Share Option. Share Options have been issued
for no consideration. Share Options do not give any rights to participate in dividends nor to participate in any pro rata issue of securities to
Shareholders.
The amount payable upon exercise of each Share Option is $0.20 (Exercise Price). The Share Options are exercisable from 1 July 2022 until
their Expiry Date, 30 June 2023. Once a Share Option is capable of exercise, it may be exercised at any time up until the Expiry Date. Share
Options not exercised before the Expiry Date will automatically lapse. Shares issued on exercise of the Share Options rank equally with the
then issued shares of the Company.
All Share Options become exercisable if the Company is subject to a change of control event and in the event that the Share Options have
not been exercised before a scheme of arrangement record date or issue of compulsory acquisition notice in the case of a takeover, the
Company will cancel the Share Options and pay a settlement fee to the participant of the greater of 5 cents per Share Option or an amount
equal to the consideration offered under the scheme of arrangement or takeover bid minus the Exercise Price.
All of a participant's Share Options will lapse on the earliest to occur of:
a)
b)
•
•
30 June.
Participation
Following a review of the Company’s incentive plans in 2021, Central established an EIP for key executives to align executive performance
with the achievement of key objectives for FY2022 and the following two years. No further grants will be made to participating executives
under the existing LTIP, ESOP and STIP as these plans have effectively been replaced by the EIP.
As the ESOP Share Options granted in 2019 were granted as incentives for three years, including FY2022, to avoid a double reward for that
year, the maximum reward that can be obtained under the EIP will be proportionately reduced by the value of any ESOP Share Options that
are subsequently exercised.
Key terms and vesting conditions
The EIP is an integrated incentive with both short term and long term components. The value of the EIP that is awarded is determined at
the end of the first 12-month performance period upon measurement of performance against Board established KPI targets for that year.
The incentive awarded is then split into two components:
33% is paid at that time (i.e. at the end of the initial 12-month performance period); and
The 67% balance of the awarded incentive value is granted as Service Rights that vest over the next three years in equal tranches
beginning 12-months after the end of the initial 12-month performance period.
The maximum opportunity for the executive team as a percentage of TFR is:
CEO: 120%
Other eligible executives: 80%
The Board has ultimate discretion to assess the achievement of the KPI targets, including application of an overriding good conduct
‘gateway’. The Board can determine whether the award payment at the end of the first performance period is paid as cash or equivalent
Company securities. Vested Service Rights may be exercised in accordance with the Employee Rights Plan Rules.
The number of Service Rights awarded for any single Plan Year is determined by reference to Central’s volume weighted average share
price for the 20 trading days immediately following the release of Central’s Quarterly Activity Statement for the performance period ending
The Service Rights are the right to acquire fully paid ordinary shares for no exercise price at the end of the vesting period and can be
exercised up to five years from the grant date. To maintain alignment with shareholders, the Service Rights have a dividend and return of
capital entitlement whereby the Service Rights convert to one share plus an additional number of shares equal in value to the dividends
paid, or capital returned during the period from grant to exercise.
Service Rights do not automatically vest on change of control, but vest as a function of the service period and the circumstances of the
change in control, subject to discretion of the Board. Any Service Rights that vest on a change in control are subject to automatic exercise.
Upon cessation of employment the Service Rights remain on foot to be tested in the normal course with the Board having the discretion to
forfeit, having regard for the prevailing facts and circumstances at the time of cessation.
Details of remuneration for the Directors and key management personnel of Central Petroleum Limited and the Consolidated Entity are set
out in Section J of this report.
FY2022 Performance
After assessment of the achievement of the Corporate KPIs (refer Section H of this report) and the Company’s performance during the
year, eligible executives were entitled to receive, on average, 62.5% of their maximum EIP bonus. Of this award, 33% is scheduled to be
paid in September 2022, while the remaining 67% will be granted as Service Rights that vest over the next three years in equal tranches.
i)
ii)
the Expiry Date (30 June 2023); or
unless otherwise stated in the offer, the date that the Board determines that any service or performance conditions stipulated
in the offer as applying to the Share Options cannot be met.
H. Short Term Incentive Plan (STIP)
A participant's Share Options will lapse if a Participant ceases to be an employee, except in certain circumstances at the Board’s discretion.
The number of Share Options which will lapse is a function of the number of days between 1 July 2019 and the participant's termination
date as a proportion of the total days between 1 July 2019 and 1 July 2022.
employees.
Unless otherwise determined by the Board, a Share Option will immediately lapse if the participant purports to transfer, assign, mortgage,
charge, encumber sell or otherwise dispose of the Share Option.
FY2022 Performance
Company in future years.
At 30 June 2022, Central’s ordinary shares were trading at $0.11 per share, well below the $0.20 exercise price of the Share Options.
The STIP is a performance-based plan comprising a matrix of corporate and individual Key Performance Indicators (KPIs) for eligible
The Company’s Board sets the maximum award achievable in any year under the STIP (normally expressed as a percentage of total fixed
remuneration (TFR)), which is contingent on the achievement of the KPIs. The KPIs are set at the beginning of each year to incentivise staff
to achieve the goals in the next year that the Board consider are key to Central’s near-term performance and longer-term strategic
direction. Neither the Board nor the Company guarantee any payment from the STIP, nor do they guarantee any performance level of the
38
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
39
REMUNERATION REPORT
(AUDITED)
c.
Eligible employees who are in roles which influence and drive the strategic direction of the Company’s business or who are senior
managers with responsibility for one or more defined functions, departments or outcomes have been eligible to receive a
maximum LTIP percentage of 20% or 30% of TFR until FY2021;
d.
Eligible employees who are in roles which are focused on the key drivers of the operational parts of the Company’s business have
received a maximum LTIP percentage of 10% of TFR up until FY2021; and
e.
All other eligible employees are integral to the success of the Company obtaining its goals and objectives and may participate in
the Central Petroleum $1,000 Exempt Plan.
Conditions of the Central Petroleum $1,000 Exempt Plan include:
1.
Share Rights can only be dealt with upon vesting at the end of the three-year service period; and
2. No performance conditions apply.
In 2021, Central conducted an external review of the effectiveness of the LTIP in providing a relevant incentive to all levels of personnel.
The review took into account many factors, including the history of rewards under the scheme, taxation implications for employees, near
and longer-term drivers of shareholder value and alternative incentive scheme structures used by peers and the broader market. As a
result of the review:
i)
ii)
No further LTIPs have been granted under the existing LTIP structure described above from 1 July 2021;
The Managing Director (subject to shareholder approval) and EMT are eligible to participate in an Executive Incentive Plan (EIP)
from FY2022 (refer Section G of this report); and
iii)
Incentive for employees in categories c, d and e above will be re-weighted to a single STIP opportunity (refer Section H of this
report) and be eligible to participate in the Central Petroleum $1,000 Exempt Plan.
F. Long Term Incentive Plan – Executive Share Option Plan (ESOP)
On 7 November 2019, shareholders approved the establishment of an ESOP for certain key executives. The ESOP replaced the previous LTIP
for participating executives and any Share Options granted under the ESOP replaced the Share Rights that would otherwise have been
Participation
Shareholders.
granted in FY2020, FY2021 and FY2022 under the LTIP.
Key terms and vesting conditions
Each Share Option entitles the participant to subscribe for one Share upon exercise of the Share Option. Share Options have been issued
for no consideration. Share Options do not give any rights to participate in dividends nor to participate in any pro rata issue of securities to
The amount payable upon exercise of each Share Option is $0.20 (Exercise Price). The Share Options are exercisable from 1 July 2022 until
their Expiry Date, 30 June 2023. Once a Share Option is capable of exercise, it may be exercised at any time up until the Expiry Date. Share
Options not exercised before the Expiry Date will automatically lapse. Shares issued on exercise of the Share Options rank equally with the
then issued shares of the Company.
All Share Options become exercisable if the Company is subject to a change of control event and in the event that the Share Options have
not been exercised before a scheme of arrangement record date or issue of compulsory acquisition notice in the case of a takeover, the
Company will cancel the Share Options and pay a settlement fee to the participant of the greater of 5 cents per Share Option or an amount
equal to the consideration offered under the scheme of arrangement or takeover bid minus the Exercise Price.
All of a participant's Share Options will lapse on the earliest to occur of:
the Expiry Date (30 June 2023); or
i)
ii)
in the offer as applying to the Share Options cannot be met.
A participant's Share Options will lapse if a Participant ceases to be an employee, except in certain circumstances at the Board’s discretion.
The number of Share Options which will lapse is a function of the number of days between 1 July 2019 and the participant's termination
date as a proportion of the total days between 1 July 2019 and 1 July 2022.
Unless otherwise determined by the Board, a Share Option will immediately lapse if the participant purports to transfer, assign, mortgage,
charge, encumber sell or otherwise dispose of the Share Option.
FY2022 Performance
At 30 June 2022, Central’s ordinary shares were trading at $0.11 per share, well below the $0.20 exercise price of the Share Options.
E. Long Term Incentive Plan – Employee Rights Plan (LTIP) (continued)
G. Executive Incentive Plan (EIP)
Participation
Following a review of the Company’s incentive plans in 2021, Central established an EIP for key executives to align executive performance
with the achievement of key objectives for FY2022 and the following two years. No further grants will be made to participating executives
under the existing LTIP, ESOP and STIP as these plans have effectively been replaced by the EIP.
As the ESOP Share Options granted in 2019 were granted as incentives for three years, including FY2022, to avoid a double reward for that
year, the maximum reward that can be obtained under the EIP will be proportionately reduced by the value of any ESOP Share Options that
are subsequently exercised.
Key terms and vesting conditions
The EIP is an integrated incentive with both short term and long term components. The value of the EIP that is awarded is determined at
the end of the first 12-month performance period upon measurement of performance against Board established KPI targets for that year.
The incentive awarded is then split into two components:
a)
b)
33% is paid at that time (i.e. at the end of the initial 12-month performance period); and
The 67% balance of the awarded incentive value is granted as Service Rights that vest over the next three years in equal tranches
beginning 12-months after the end of the initial 12-month performance period.
The maximum opportunity for the executive team as a percentage of TFR is:
•
•
CEO: 120%
Other eligible executives: 80%
The Board has ultimate discretion to assess the achievement of the KPI targets, including application of an overriding good conduct
‘gateway’. The Board can determine whether the award payment at the end of the first performance period is paid as cash or equivalent
Company securities. Vested Service Rights may be exercised in accordance with the Employee Rights Plan Rules.
The number of Service Rights awarded for any single Plan Year is determined by reference to Central’s volume weighted average share
price for the 20 trading days immediately following the release of Central’s Quarterly Activity Statement for the performance period ending
30 June.
The Service Rights are the right to acquire fully paid ordinary shares for no exercise price at the end of the vesting period and can be
exercised up to five years from the grant date. To maintain alignment with shareholders, the Service Rights have a dividend and return of
capital entitlement whereby the Service Rights convert to one share plus an additional number of shares equal in value to the dividends
paid, or capital returned during the period from grant to exercise.
Service Rights do not automatically vest on change of control, but vest as a function of the service period and the circumstances of the
change in control, subject to discretion of the Board. Any Service Rights that vest on a change in control are subject to automatic exercise.
Upon cessation of employment the Service Rights remain on foot to be tested in the normal course with the Board having the discretion to
forfeit, having regard for the prevailing facts and circumstances at the time of cessation.
Details of remuneration for the Directors and key management personnel of Central Petroleum Limited and the Consolidated Entity are set
out in Section J of this report.
FY2022 Performance
After assessment of the achievement of the Corporate KPIs (refer Section H of this report) and the Company’s performance during the
year, eligible executives were entitled to receive, on average, 62.5% of their maximum EIP bonus. Of this award, 33% is scheduled to be
paid in September 2022, while the remaining 67% will be granted as Service Rights that vest over the next three years in equal tranches.
unless otherwise stated in the offer, the date that the Board determines that any service or performance conditions stipulated
H. Short Term Incentive Plan (STIP)
The STIP is a performance-based plan comprising a matrix of corporate and individual Key Performance Indicators (KPIs) for eligible
employees.
The Company’s Board sets the maximum award achievable in any year under the STIP (normally expressed as a percentage of total fixed
remuneration (TFR)), which is contingent on the achievement of the KPIs. The KPIs are set at the beginning of each year to incentivise staff
to achieve the goals in the next year that the Board consider are key to Central’s near-term performance and longer-term strategic
direction. Neither the Board nor the Company guarantee any payment from the STIP, nor do they guarantee any performance level of the
Company in future years.
38
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
39
REMUNERATION REPORT
(AUDITED)
H. Short Term Incentive Plan (STIP) (continued)
H. Short Term Incentive Plan (STIP) (continued)
Participation in the STIP, or the provision of any Company security, does not form part of the participating employee's remuneration for
the purposes of determining payments in lieu of notice of termination of employment, severance payments, leave entitlements, or any
other compensation payable to a participating employee upon the termination of employment (unless the Board otherwise determines).
Participation
The STIP operates with three levels of participation for eligible employees, each with a different level of maximum reward:
Safety and Environment KPIs for FY2022:
Objective
Weighting
Performance Outcome for FY2022
0%
50%
75%
100%
STIP participation level
1
2
3
Maximum
% of TFR
30 %
20 %
10 %
The maximum STIP % available in FY2022 increased from previous years for some eligible employees as they are no longer be eligible to
receive grants under the LTIP (apart from the Central Petroleum $1,000 Plan).
At the start of each performance period, the CEO nominates a level of participation for each eligible employee after considering factors
such as the eligible employee’s:
a)
b)
c)
d)
Role and responsibilities;
Involvement in strategic and operational aspects of management;
Ability to be a key driver of the operational parts of the Company’s business; and
Ability to influence the Company’s performance.
From 1 July 2021, the CEO and executives who participate in the EIP are not eligible to participate in the STIP (refer Section G of this
report).
At the Board’s discretion the STIP award may be paid through a combination of cash and/or Company securities.
FY2022 Performance
After assessment of the achievement of the KPIs below and the Company’s performance during the year, eligible employees were entitled
to receive, on average, 62.75% of their maximum STIP bonus. The STIP bonuses are scheduled to be paid in September 2022.
The Financial Year 2022 STIP (FY2022 STIP) was designed to recognise and reward individual effort by connecting individual KPIs and
corporate KPIs and was assessed across three categories:
Table 1: Realised Remuneration
KPI Category
Corporate KPIs
Safety and Environment KPI’s
Individual KPIs
Percent Allocation of STIP
Maximum
Achieved
50 %
10 %
40 %
100 %
31.25 %
7.50 %
24.00 % (avg)
62.75 % (avg)
The majority of employees could earn a maximum of 10% of TFR, whilst more senior employees could earn either a maximum of 20% or
30% of TFR from the FY2022 STIP, depending on their participation level.
Corporate KPIs for FY2022:
Objective
Revenue
Assessed against budget
Total Cost1
Total company operating and capital expenditure for
agreed scope of works assessed against budget
Exploration (Dingo Deep & PV Deep)
Assessed against budget, commercial viability, schedule
and timing hurdles
Range Gas Project
Assessed against budget, schedule and timing hurdles
Weighting
Performance Outcome for FY2022
0%
25%
100%
125%
25%
25%
25%
25%
Traditional Owner cultural heritage
Safety: Total Recordable Incident Frequency Rate
(TRIFR)
Environment: Recordable environmental incidents
Alice Springs local and indigenous employment
25%
25%
25%
25%
Individual KPIs
Individual KPIs provide significant relevance to each role in each department, and for FY2022 were assessed as achieving an average of 60%
(or a weighted average of 24% out of a maximum possible 40%).
I. Realised Remuneration
Table 1 identifies the Actual Remuneration received by Senior Executives in respect of the 2022 financial year. Realised Remuneration
reflects the take home remuneration of the Executive and includes:
Total fixed remuneration inclusive of company superannuation contributions;
Any Short Term Incentive awarded as cash for the financial year but paid after the end of the financial year;
Any Short Term Incentive awarded as share rights in lieu of cash for the financial year, and granted after the end of the financial
year valued at the cash equivalent amount (but excluding any share rights which do not immediately vest); and
The value of LTIP share rights vesting (if any) in respect of the three-year period ending 30 June, valued at the year-end share
price (2022: 11.0 cents per share, 2021: 11.5 cents per share).
•
•
•
•
The table below has been provided to assist shareholders to understand the remuneration received in respect of each financial year ending
30 June. The table is a voluntary disclosure and as such has not been prepared in accordance with the disclosure requirements of the
Accounting Standards or Corporations Act 2001. See Table 2 for Executive KMP remuneration in accordance with these requirements.
Executive KMP
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson4
Jonathan Snape5
Daniel White
Year
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
Total Fixed
Remuneration1
$
STIP / EIP
Benefits2
Shares3
Other
LTI Vested as
$
$
625,750
612,061
511,860
500,404
338,050
330,001
409,450
400,001
—
335,132
330,001
—
454,410
444,080
156,438
42,231
85,310
34,527
56,342
21,449
68,242
25,999
—
21,783
55,000
—
75,735
28,864
7,470
7,635
7,470
7,635
7,470
7,635
7,470
7,635
—
7,635
6,984
—
7,470
7,635
66,549
28,214
$
—
—
—
—
—
—
—
—
—
21,861
46,505
29,160
46,505
145,784
Total
$
789,658
728,476
604,640
570,780
401,862
359,085
485,162
433,635
—
386,411
391,985
—
584,120
509,739
3,257,427
2,988,126
Total Executive KMP
2,669,521
2,621,679
497,067
174,853
44,334
45,810
1 Total Fixed Remuneration includes salaries, fees and superannuation contributions.
2
Includes car parking and other fringe benefits.
3 Long Term Incentive Vested as Shares comprises any LTI from prior years that was awarded or is expected to be awarded for the three-year period ending 30 June
and valued at that date.
4 Robin Polson resigned 30 June 2021.
5
Jonathan Snape commenced 1 July 2021.
1 Not rewarded for works that were essential but not completed, e.g. capital project delay or deferral. Excludes exploration which is assessed as a separate KPI.
40 CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
41
REMUNERATION REPORT
(AUDITED)
Participation in the STIP, or the provision of any Company security, does not form part of the participating employee's remuneration for
the purposes of determining payments in lieu of notice of termination of employment, severance payments, leave entitlements, or any
other compensation payable to a participating employee upon the termination of employment (unless the Board otherwise determines).
The STIP operates with three levels of participation for eligible employees, each with a different level of maximum reward:
Participation
STIP participation level
1
2
3
Maximum
% of TFR
30 %
20 %
10 %
The maximum STIP % available in FY2022 increased from previous years for some eligible employees as they are no longer be eligible to
receive grants under the LTIP (apart from the Central Petroleum $1,000 Plan).
At the start of each performance period, the CEO nominates a level of participation for each eligible employee after considering factors
such as the eligible employee’s:
Role and responsibilities;
a)
b)
c)
d)
report).
Involvement in strategic and operational aspects of management;
Ability to be a key driver of the operational parts of the Company’s business; and
Ability to influence the Company’s performance.
From 1 July 2021, the CEO and executives who participate in the EIP are not eligible to participate in the STIP (refer Section G of this
At the Board’s discretion the STIP award may be paid through a combination of cash and/or Company securities.
FY2022 Performance
After assessment of the achievement of the KPIs below and the Company’s performance during the year, eligible employees were entitled
to receive, on average, 62.75% of their maximum STIP bonus. The STIP bonuses are scheduled to be paid in September 2022.
KPI Category
Corporate KPIs
Safety and Environment KPI’s
Individual KPIs
Percent Allocation of STIP
Maximum
50 %
10 %
40 %
100 %
Achieved
31.25 %
7.50 %
24.00 % (avg)
62.75 % (avg)
The majority of employees could earn a maximum of 10% of TFR, whilst more senior employees could earn either a maximum of 20% or
30% of TFR from the FY2022 STIP, depending on their participation level.
Weighting
Performance Outcome for FY2022
0%
25%
100%
125%
Corporate KPIs for FY2022:
Objective
Revenue
Total Cost1
Assessed against budget
Total company operating and capital expenditure for
agreed scope of works assessed against budget
Exploration (Dingo Deep & PV Deep)
Assessed against budget, commercial viability, schedule
and timing hurdles
Range Gas Project
Assessed against budget, schedule and timing hurdles
25%
25%
25%
25%
1 Not rewarded for works that were essential but not completed, e.g. capital project delay or deferral. Excludes exploration which is assessed as a separate KPI.
H. Short Term Incentive Plan (STIP) (continued)
H. Short Term Incentive Plan (STIP) (continued)
Safety and Environment KPIs for FY2022:
Objective
Weighting
Performance Outcome for FY2022
0%
50%
75%
100%
Traditional Owner cultural heritage
Safety: Total Recordable Incident Frequency Rate
(TRIFR)
Environment: Recordable environmental incidents
Alice Springs local and indigenous employment
25%
25%
25%
25%
Individual KPIs
Individual KPIs provide significant relevance to each role in each department, and for FY2022 were assessed as achieving an average of 60%
(or a weighted average of 24% out of a maximum possible 40%).
I. Realised Remuneration
Table 1 identifies the Actual Remuneration received by Senior Executives in respect of the 2022 financial year. Realised Remuneration
reflects the take home remuneration of the Executive and includes:
•
•
•
•
Total fixed remuneration inclusive of company superannuation contributions;
Any Short Term Incentive awarded as cash for the financial year but paid after the end of the financial year;
Any Short Term Incentive awarded as share rights in lieu of cash for the financial year, and granted after the end of the financial
year valued at the cash equivalent amount (but excluding any share rights which do not immediately vest); and
The value of LTIP share rights vesting (if any) in respect of the three-year period ending 30 June, valued at the year-end share
price (2022: 11.0 cents per share, 2021: 11.5 cents per share).
The table below has been provided to assist shareholders to understand the remuneration received in respect of each financial year ending
30 June. The table is a voluntary disclosure and as such has not been prepared in accordance with the disclosure requirements of the
Accounting Standards or Corporations Act 2001. See Table 2 for Executive KMP remuneration in accordance with these requirements.
The Financial Year 2022 STIP (FY2022 STIP) was designed to recognise and reward individual effort by connecting individual KPIs and
corporate KPIs and was assessed across three categories:
Table 1: Realised Remuneration
Executive KMP
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson4
Jonathan Snape5
Daniel White
Total Executive KMP
Year
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
Total Fixed
Remuneration1
$
STIP / EIP
$
Other
Benefits2
$
LTI Vested as
Shares3
$
625,750
612,061
511,860
500,404
338,050
330,001
409,450
400,001
—
335,132
330,001
—
454,410
444,080
156,438
42,231
85,310
34,527
56,342
21,449
68,242
25,999
—
21,783
55,000
—
75,735
28,864
7,470
7,635
7,470
7,635
7,470
7,635
7,470
7,635
—
7,635
6,984
—
7,470
7,635
—
66,549
—
28,214
—
—
—
—
—
21,861
—
—
46,505
29,160
Total
$
789,658
728,476
604,640
570,780
401,862
359,085
485,162
433,635
—
386,411
391,985
—
584,120
509,739
2,669,521
2,621,679
497,067
174,853
44,334
45,810
46,505
145,784
3,257,427
2,988,126
1 Total Fixed Remuneration includes salaries, fees and superannuation contributions.
2
3 Long Term Incentive Vested as Shares comprises any LTI from prior years that was awarded or is expected to be awarded for the three-year period ending 30 June
Includes car parking and other fringe benefits.
and valued at that date.
4 Robin Polson resigned 30 June 2021.
5
Jonathan Snape commenced 1 July 2021.
40 CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
41
REMUNERATION REPORT
(AUDITED)
J. Remuneration Details – Statutory tables
Table 2: Remuneration of Directors and Key Management Personnel
Short-Term
Post-Employment
Long-
Term
Benefits
Share-
Based
Payments
Variable
Remuneration
Awarded
%
Forfeited
%
Non-
Monetary
Benefits
$
STI1
$
Superannuation
Contributions
$
Termination
Benefits
$
LSL
(Accrued)
$
Rights &
Options2
$
Total
$
Percent of
Remuneration
%
Non-Executive Directors
Stuart Baker
2022
2021
Stephen Gardiner3
2022
2021
Katherine Hirschfeld 2022
2021
Agu Kantsler
2022
2021
Salary/
Fees
$
67,500
85,000
62,500
—
78,000
85,833
62,500
78,333
Michael McCormack4 2022
2021
117,500
107,500
Former Non-Executive Directors
Julian Fowles5
Wrixon Gasteen6
Sub-total
Executives
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson7
Jonathan Snape8
Daniel White
Sub-total
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
—
26,667
—
64,167
388,000
447,500
613,881
623,324
501,018
499,881
321,088
318,460
400,660
392,139
—
318,593
315,318
—
450,596
444,673
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
156,438
42,231
85,310
34,527
56,342
21,449
68,242
25,999
—
21,783
55,000
—
75,735
28,864
7,470
7,635
7,470
7,635
7,470
7,635
7,470
7,635
—
7,635
6,984
—
7,470
7,635
2022 2,602,561
2,597,070
2021
497,067
174,853
44,334
45,810
Total Remuneration 2022 2,990,561
3,044,570
2021
497,067
174,853
44,334
45,810
6,750
8,075
6,250
—
7,800
8,154
6,250
7,442
11,750
10,212
—
2,533
—
6,096
38,800
42,512
23,568
21,694
23,568
21,694
23,568
21,694
23,568
21,694
—
21,694
23,568
—
23,568
21,694
141,408
130,164
180,208
172,676
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
13,639
11,221
7,119
8,690
4,470
4,218
5,506
5,308
—
5,870
2,706
—
10,367
8,140
18,603
—
18,603
—
7,441
—
18,603
—
34,548
—
—
—
—
—
97,798
—
277,153
341,098
241,598
223,072
158,595
130,751
192,505
158,892
—
134,477
39,722
—
151,392
123,785
92,853
93,075
87,353
—
93,241
93,987
87,353
85,775
163,798
117,712
—
29,200
—
70,263
524,598
490,012
1,092,149
1,047,203
866,083
795,499
571,533
504,207
697,951
611,667
—
510,052
443,298
—
719,128
634,791
43,807
43,447
1,060,965
1,112,075
43,807
43,447
1,158,763
1,112,075
4,390,142
4,103,419
4,914,740
4,593,431
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
40%
37%
38%
32%
38%
30%
37%
30%
—
31%
21%
—
32%
24%
35%
31%
32%
28%
1 Short term incentives are unpaid at the end of the financial year.
2 The fair values of share rights granted are valued using methodology that takes into account market and peer performance hurdles. The values of rights are
calculated at the date of grant using a Black Scholes valuation model and Monte Carlo simulations and an agreed comparator group to assess relative total
shareholder return. The values are allocated to each reporting period evenly over the period from grant date to vesting date. In the event that rights are cancelled
for failure to meet the required service period or are not retained on termination of employment, any amounts previously expensed as share based payments are
reversed as negative amounts. In 2022 non-executive directors had the discretion to sacrifice up to 25% of their FY2022 Base Fees to earn share rights which
automatically vested on 30 June 2022.
3 Stephen Gardiner was appointed 1 July 2021.
4 Mr McCormack commenced 1 September 2020.
5 Julian Fowles resigned 31 October 2020.
6 Wrix Gasteen resigned 28 November 2020.
7 Robin Polson resigned 30 June 2021.
8
Jonathan Snape commenced 1 July 2021.
42
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 43
J. Remuneration Details – Statutory tables (continued)
Table 3: Short Term Incentives Awarded
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
Maximum
$
250,300
61,206
136,496
50,040
90,147
33,000
109,187
40,000
—
33,513
88,000
—
121,176
44,408
795,306
262,167
Awarded
$
156,438
42,231
85,310
34,527
56,342
21,449
68,242
25,999
—
21,783
55,000
—
75,735
28,864
497,067
174,853
62.5%
69.0%
62.5%
69.0%
62.5%
65.0%
62.5%
65.0%
—
65.0%
62.5%
—
62.5%
65.0%
62.5%
66.7%
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
37.5%
31.0%
37.5%
31.0%
37.5%
35.0%
37.5%
35.0%
—
35.0%
37.5%
—
37.5%
35.0%
37.5%
33.3%
—
—
—
—
—
—
—
—
—
—
—
30 Jun 26
30 Jun 26
30 Jun 26
30 Jun 26
30 Jun 26
30 Jun 25
30 Jun 25
30 Jun 25
30 Jun 25
30 Jun 25
30 Jun 25
30 Jun 25
Table 4: Share Based Compensation – Share Rights Granted to Key Management Personnel during the Year
Number of Rights
Granted
Grant Date
Average
Fair Value at
Average Exercise
Grant Date
Price Per Right
Expiry Date
Non-Executive Directors
Stuart Baker
161,765
23 Nov 21
Stephen Gardiner
161,765
23 Nov 21
Katherine Hirschfeld
64,706
23 Nov 21
Agu Kantsler
161,765
23 Nov 21
Michael McCormack
300,420
23 Nov 21
20221
2021
20221
2021
20221
2021
20221
2021
20221
2021
2022
2021
2022
20212
2022
20212
2022
20212
2022
20212
2022
20212
2022
20212
2021
2022
2021
2022
2021
—
—
—
—
—
—
—
—
—
—
—
0.115
—
0.115
—
0.115
—
0.115
—
0.115
—
—
—
—
—
—
—
496,171
11 Nov 20
$0.130
405,655
11 Nov 20
$0.130
243,198
11 Nov 20
$0.130
304,213
11 Nov 20
$0.130
246,979
11 Nov 20
$0.130
11 Nov 20
24 Jul 20
$0.130
$0.065
—
—
—
—
—
—
—
—
—
—
—
—
—
850,421
327,269
1,510,476
3,533,961
850,421
3,533,961
1 Represents a portion of Directors Fees sacrificed for FY2022. These Share Rights vested on 30 June 2022 – Refer Section L of this report.
2 Represents FY2020 STIP settled as Equity in the form of deferred share rights.
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson
Jonathan Snape
Daniel White
Total
Sub-total
Executives
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson
Daniel White
Sub-total
Total
REMUNERATION REPORT
(AUDITED)
J. Remuneration Details – Statutory tables
Table 2: Remuneration of Directors and Key Management Personnel
Short-Term
Post-Employment
Benefits
Payments
Long-
Term
Share-
Based
Variable
Remuneration
Salary/
Fees
$
Non-
Monetary
Benefits
$
STI1
$
Superannuation
Termination
Contributions
Benefits
(Accrued)
$
$
LSL
$
Rights &
Options2
$
Total
$
Percent of
Remuneration
%
6,750
8,075
6,250
—
7,800
8,154
6,250
7,442
11,750
10,212
—
2,533
—
6,096
38,800
42,512
23,568
21,694
23,568
21,694
23,568
21,694
23,568
21,694
—
21,694
23,568
—
23,568
21,694
141,408
130,164
180,208
172,676
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
13,639
11,221
7,119
8,690
4,470
4,218
5,506
5,308
—
5,870
2,706
—
10,367
8,140
18,603
18,603
—
—
7,441
—
18,603
34,548
—
—
—
—
—
—
—
97,798
277,153
341,098
241,598
223,072
158,595
130,751
192,505
158,892
—
134,477
39,722
—
151,392
123,785
92,853
93,075
87,353
—
93,241
93,987
87,353
85,775
163,798
117,712
29,200
—
—
70,263
524,598
490,012
1,092,149
1,047,203
866,083
795,499
571,533
504,207
697,951
611,667
—
510,052
443,298
—
719,128
634,791
43,807
43,447
1,060,965
1,112,075
43,807
43,447
1,158,763
1,112,075
4,390,142
4,103,419
4,914,740
4,593,431
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
40%
37%
38%
32%
38%
30%
37%
30%
—
31%
21%
—
32%
24%
35%
31%
32%
28%
Non-Executive Directors
Stuart Baker
Stephen Gardiner3
Katherine Hirschfeld 2022
Agu Kantsler
Michael McCormack4 2022
Former Non-Executive Directors
Julian Fowles5
Wrixon Gasteen6
Sub-total
Executives
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson7
Jonathan Snape8
Daniel White
Sub-total
2022
2021
2022
2021
2021
2022
2021
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
67,500
85,000
62,500
—
78,000
85,833
62,500
78,333
117,500
107,500
26,667
—
—
64,167
388,000
447,500
613,881
623,324
501,018
499,881
321,088
318,460
400,660
392,139
156,438
42,231
85,310
34,527
56,342
21,449
68,242
25,999
318,593
21,783
315,318
55,000
—
—
—
—
450,596
444,673
75,735
28,864
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
7,470
7,635
7,470
7,635
7,470
7,635
7,470
7,635
—
7,635
6,984
—
7,470
7,635
2022 2,602,561
2021
2,597,070
497,067
174,853
44,334
45,810
Total Remuneration 2022 2,990,561
2021
3,044,570
497,067
174,853
44,334
45,810
1 Short term incentives are unpaid at the end of the financial year.
automatically vested on 30 June 2022.
3 Stephen Gardiner was appointed 1 July 2021.
4 Mr McCormack commenced 1 September 2020.
5 Julian Fowles resigned 31 October 2020.
6 Wrix Gasteen resigned 28 November 2020.
7 Robin Polson resigned 30 June 2021.
8
Jonathan Snape commenced 1 July 2021.
2 The fair values of share rights granted are valued using methodology that takes into account market and peer performance hurdles. The values of rights are
calculated at the date of grant using a Black Scholes valuation model and Monte Carlo simulations and an agreed comparator group to assess relative total
shareholder return. The values are allocated to each reporting period evenly over the period from grant date to vesting date. In the event that rights are cancelled
for failure to meet the required service period or are not retained on termination of employment, any amounts previously expensed as share based payments are
reversed as negative amounts. In 2022 non-executive directors had the discretion to sacrifice up to 25% of their FY2022 Base Fees to earn share rights which
J. Remuneration Details – Statutory tables (continued)
Table 3: Short Term Incentives Awarded
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson
Jonathan Snape
Daniel White
Total
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
Maximum
$
250,300
61,206
136,496
50,040
90,147
33,000
109,187
40,000
—
33,513
88,000
—
121,176
44,408
795,306
262,167
Awarded
$
156,438
42,231
85,310
34,527
56,342
21,449
68,242
25,999
—
21,783
55,000
—
75,735
28,864
497,067
174,853
Awarded
%
Forfeited
%
62.5%
69.0%
62.5%
69.0%
62.5%
65.0%
62.5%
65.0%
—
65.0%
62.5%
—
62.5%
65.0%
62.5%
66.7%
37.5%
31.0%
37.5%
31.0%
37.5%
35.0%
37.5%
35.0%
—
35.0%
37.5%
—
37.5%
35.0%
37.5%
33.3%
Table 4: Share Based Compensation – Share Rights Granted to Key Management Personnel during the Year
Number of Rights
Granted
Grant Date
Average
Fair Value at
Grant Date
Average Exercise
Price Per Right
Expiry Date
Non-Executive Directors
Stuart Baker
Stephen Gardiner
Katherine Hirschfeld
Agu Kantsler
Michael McCormack
Sub-total
Executives
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson
Daniel White
Sub-total
Total
20221
2021
20221
2021
20221
2021
20221
2021
20221
2021
2022
2021
2022
20212
2022
20212
2022
20212
2022
20212
2022
20212
2022
20212
2021
2022
2021
2022
2021
23 Nov 21
—
23 Nov 21
—
23 Nov 21
—
23 Nov 21
—
23 Nov 21
—
—
11 Nov 20
—
11 Nov 20
—
11 Nov 20
—
11 Nov 20
—
11 Nov 20
—
11 Nov 20
24 Jul 20
0.115
—
0.115
—
0.115
—
0.115
—
0.115
—
—
$0.130
—
$0.130
—
$0.130
—
$0.130
—
$0.130
—
$0.130
$0.065
161,765
—
161,765
—
64,706
—
161,765
—
300,420
—
850,421
—
—
496,171
—
405,655
—
243,198
—
304,213
—
246,979
—
327,269
1,510,476
—
3,533,961
850,421
3,533,961
1 Represents a portion of Directors Fees sacrificed for FY2022. These Share Rights vested on 30 June 2022 – Refer Section L of this report.
2 Represents FY2020 STIP settled as Equity in the form of deferred share rights.
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
30 Jun 26
—
30 Jun 26
—
30 Jun 26
—
30 Jun 26
—
30 Jun 26
—
—
30 Jun 25
—
30 Jun 25
—
30 Jun 25
—
30 Jun 25
—
30 Jun 25
—
30 Jun 25
30 Jun 25
42
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 43
REMUNERATION REPORT
(AUDITED)
J. Remuneration Details – Statutory tables (continued)
J. Remuneration Details – Statutory tables (continued)
The following factors and assumptions were used in determining the fair value of rights granted to key management personnel during
FY2022:
Grant Date
Expiry Date
Fair Value
Per Right
Exercise
Price
Price of Shares
at Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
23 Nov 20211
30 Jun 2026
$0.115
Nil
$0.115
N/A
N/A
—
1 Share Rights granted to Non-Executive Directors. The fair value reflects the value of Director Fees sacrificed – Refer Section L of this report.
The following factors and assumptions were used in determining the fair value of rights granted to key management personnel during
FY2021:
Grant Date
Expiry Date
24 Jul 20201
11 Nov 20202
30 Jun 2025
30 Jun 2025
Fair Value
Per Right
Exercise
Price
Price of Shares
at Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
$0.065
$0.130
Nil
Nil
$0.089
$0.130
72%
N/A
0.43%
N/A
—
—
1 LTIP Rights for the plan year commencing 1 July 2020.
2 Deferred Share Rights awarded in lieu of cash under the STIP for the year ended 30 June 2020.
Table 5: Share Based Compensation – Share Rights Vested to Key Management Personnel during the Year
Leon Devaney
Ross Evans
Robin Polson
Daniel White
Total
Maximum
Number of
Rights Eligible
for Vesting
—
1,837,109
—
778,854
—
603,491
983,204
804,984
983,204
4,024,438
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
LTIP Year
Commencing
STIP Year
Commencing
Number of
Rights Vested1
Proportion of
LTIP Rights
Vested2
Proportion of
LTIP Rights
Forfeited3
—
01 Jul 18
—
01 Jul 18
—
01 Jul 18
01 Jul 19
01 Jul 18
—
N/A
—
N/A
—
N/A
N/A
N/A
—
578,689
—
245,339
—
190,099
422,777
253,569
422,777
1,267,696
—
31.5%
—
31.5%
—
31.5%
43.0%
31.5%
43.0%
31.5%
—
68.5%
—
68.5%
—
68.5%
57.0%
68.5%
57.0%
68.5%
1 The number of Rights that vested during FY2021 relates to Rights granted in prior financial years under the Long Term Incentive Plan.
2 The proportion of Rights vested represents the proportion of the maximum number of Rights that were eligible for vesting during the financial year under the Long
Term Incentive Plan.
3 Prior to forfeiture and at the discretion of the Board, Rights may be subjected to retest against the performance hurdles at 31 December 2022.
In addition, 850,421 Share Rights vested on 30 June 2022, representing 100% of Share Rights granted during the year to Non-Executive
Directors in return for the sacrifice of Directors’ fees – refer Table 4 above.
Share, Rights and Option Holdings of Key Management Personnel
Key Management Personnel may receive Service Rights to shares of the Company under the Executive Incentive Plan (refer Section G of
this report).
Key Management Personnel have, in previous years, participated in the Group’s Long Term Incentive Plans under which they may have
received:
a)
Rights to shares of the Company under the Employee Rights Plan (refer Section E of this report); and
b) Options over shares of the Company under the Executive Share Option Plan (refer Section F of this report).
In FY2022, Non-Executive Directors were entitled to sacrifice up to 25% of their Base Fee to earn Share Rights which vested on 30 June
2022.
The maximum number of rights to ordinary shares in the Company under the long term incentive plan held during the financial year by
other key management personnel of the Consolidated Entity, including their personally related parties, are set out below:
Table 6: Share Rights Holdings of Key Management Personnel
Number of
Rights Held
at Start of
Maximum
Number
Granted as
Year
Compensation
Cancelled
During the
Year
Converted to
Shares
Retained on
Departure
Number of
Rights Held
at End of
Number of
Rights Held
at End of
Year
Year
(Vested)
(Unvested)
Share Rights
Non-executive Directors
Stuart Baker
Stephen Gardiner
Katherine Hirschfeld
Agu Kantsler
Michael McCormack
Sub-total
Executives
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson1
Daniel White
Sub-total
Total
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2021
2021
2022
2021
2022
2021
2022
2021
2022
2021
—
—
N/A
N/A
—
—
—
—
—
—
—
N/A
2,333,280
2,727,734
1,184,509
778,854
243,198
304,213
—
—
N/A
603,491
3,625,933
2,524,507
7,691,133
6,634,586
7,691,133
6,634,586
161,765
161,765
64,706
161,765
300,420
850,421
405,655
243,198
304,213
246,979
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1,258,420)
496,171
(890,625)
(533,515)
(245,339)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
—
161,765
—
161,765
N/A
64,706
161,765
300,420
850,421
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
N/A
—
—
—
—
—
—
—
—
—
—
—
1,074,860
2,333,280
405,655
1,184,509
243,198
243,198
304,213
304,213
N/A
N/A
2,820,949
3,625,933
4,848,875
7,691,133
4,848,875
7,691,133
850,470
N/A
N/A
(253,569)
(498,908)
1,837,745
3,533,961
(551,415)
(736,319)
(2,343,350)
(1,626,944)
850,421
3,533,961
(2,343,350)
(1,626,944)
(498,908)
—
850,421
850,470
850,470
1 Robin Polson resigned 30 June 2021. Of the 850,470 Share Rights held at that date, 437,078 Share Rights were cancelled post departure.
44
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 45
J. Remuneration Details – Statutory tables (continued)
J. Remuneration Details – Statutory tables (continued)
The maximum number of rights to ordinary shares in the Company under the long term incentive plan held during the financial year by
other key management personnel of the Consolidated Entity, including their personally related parties, are set out below:
Table 6: Share Rights Holdings of Key Management Personnel
Share Rights
Non-executive Directors
Stuart Baker
Stephen Gardiner
Katherine Hirschfeld
Agu Kantsler
Michael McCormack
Sub-total
Executives
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson1
Daniel White
Sub-total
Total
Number of
Rights Held
at Start of
Year
Maximum
Number
Granted as
Compensation
Cancelled
During the
Year
Converted to
Shares
Retained on
Departure
Number of
Rights Held
at End of
Year
(Vested)
Number of
Rights Held
at End of
Year
(Unvested)
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2021
2021
2022
2021
2022
2021
2022
2021
2022
2021
—
—
N/A
N/A
—
—
—
—
—
N/A
—
—
2,333,280
2,727,734
1,184,509
778,854
243,198
—
304,213
—
N/A
603,491
3,625,933
2,524,507
7,691,133
6,634,586
7,691,133
6,634,586
161,765
—
161,765
—
64,706
—
161,765
—
300,420
—
850,421
—
—
496,171
—
405,655
—
243,198
—
304,213
—
246,979
—
—
—
—
—
—
—
—
—
—
—
—
(1,258,420)
(890,625)
(533,515)
—
—
—
—
—
—
—
—
1,837,745
(551,415)
(736,319)
—
3,533,961
(2,343,350)
(1,626,944)
850,421
3,533,961
(2,343,350)
(1,626,944)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(245,339)
—
—
—
—
—
—
—
(253,569)
—
(498,908)
—
(498,908)
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
850,470
N/A
N/A
—
850,470
—
850,470
161,765
—
161,765
N/A
64,706
—
161,765
—
300,420
—
850,421
—
—
—
—
N/A
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
N/A
N/A
—
—
—
—
1,074,860
2,333,280
405,655
1,184,509
243,198
243,198
304,213
304,213
N/A
N/A
2,820,949
3,625,933
4,848,875
7,691,133
850,421
—
4,848,875
7,691,133
1 Robin Polson resigned 30 June 2021. Of the 850,470 Share Rights held at that date, 437,078 Share Rights were cancelled post departure.
REMUNERATION REPORT
(AUDITED)
The following factors and assumptions were used in determining the fair value of rights granted to key management personnel during
Grant Date
Expiry Date
Fair Value
Per Right
Exercise
Price
Price of Shares
at Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
23 Nov 20211
30 Jun 2026
$0.115
Nil
$0.115
N/A
N/A
—
1 Share Rights granted to Non-Executive Directors. The fair value reflects the value of Director Fees sacrificed – Refer Section L of this report.
The following factors and assumptions were used in determining the fair value of rights granted to key management personnel during
Grant Date
Expiry Date
24 Jul 20201
11 Nov 20202
30 Jun 2025
30 Jun 2025
Fair Value
Per Right
Exercise
Price
Price of Shares
at Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
$0.065
$0.130
Nil
Nil
$0.089
$0.130
72%
N/A
0.43%
N/A
—
—
1 LTIP Rights for the plan year commencing 1 July 2020.
2 Deferred Share Rights awarded in lieu of cash under the STIP for the year ended 30 June 2020.
Table 5: Share Based Compensation – Share Rights Vested to Key Management Personnel during the Year
Rights Eligible
LTIP Year
STIP Year
Number of
for Vesting
Commencing
Commencing
Rights Vested1
Proportion of
Proportion of
LTIP Rights
Vested2
LTIP Rights
Forfeited3
Maximum
Number of
—
—
—
603,491
983,204
804,984
983,204
4,024,438
1,837,109
01 Jul 18
778,854
01 Jul 18
—
—
—
01 Jul 18
01 Jul 19
01 Jul 18
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
—
N/A
—
N/A
—
N/A
N/A
N/A
578,689
245,339
—
—
—
190,099
422,777
253,569
422,777
1,267,696
—
31.5%
—
31.5%
—
31.5%
43.0%
31.5%
43.0%
31.5%
—
68.5%
—
68.5%
—
68.5%
57.0%
68.5%
57.0%
68.5%
1 The number of Rights that vested during FY2021 relates to Rights granted in prior financial years under the Long Term Incentive Plan.
2 The proportion of Rights vested represents the proportion of the maximum number of Rights that were eligible for vesting during the financial year under the Long
Term Incentive Plan.
3 Prior to forfeiture and at the discretion of the Board, Rights may be subjected to retest against the performance hurdles at 31 December 2022.
In addition, 850,421 Share Rights vested on 30 June 2022, representing 100% of Share Rights granted during the year to Non-Executive
Directors in return for the sacrifice of Directors’ fees – refer Table 4 above.
Share, Rights and Option Holdings of Key Management Personnel
Key Management Personnel may receive Service Rights to shares of the Company under the Executive Incentive Plan (refer Section G of
Key Management Personnel have, in previous years, participated in the Group’s Long Term Incentive Plans under which they may have
a)
Rights to shares of the Company under the Employee Rights Plan (refer Section E of this report); and
b) Options over shares of the Company under the Executive Share Option Plan (refer Section F of this report).
In FY2022, Non-Executive Directors were entitled to sacrifice up to 25% of their Base Fee to earn Share Rights which vested on 30 June
FY2022:
FY2021:
Leon Devaney
Ross Evans
Robin Polson
Daniel White
Total
this report).
received:
2022.
44
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 45
REMUNERATION REPORT
(AUDITED)
J. Remuneration Details – Statutory tables (continued)
The number of Options to ordinary shares in the Company under the Executive Share Option Plan held during the financial year by key
management personnel of the Consolidated Entity, including their personally related parties, are set out below:
Table 7: Vesting profile of Share Rights Holdings of Key Management Personnel
Grant Date
Type
Maximum Number
of Unvested Rights
at 30 June 2022
Vesting Date
Maximum value
yet to vest2
Key Management Personnel
TBD1
Leon Devaney
11 Nov 2020
Ross Evans
Damian Galvin
Duncan Lockhart
TBD1
11 Nov 2020
TBD1
11 Nov 2020
TBD1
11 Nov 2020
Deferred Share Rights – FY2022 EIP1
Deferred Share Rights – STIP3
Deferred Share Rights – FY2022 EIP1
Deferred Share Rights - STIP3
Deferred Share Rights – FY2022 EIP1
Deferred Share Rights - STIP3
Deferred Share Rights – FY2022 EIP1
Deferred Share Rights - STIP3
Jonathan Snape
TBD1
Deferred Share Rights – FY2022 EIP1
Daniel White
Total
TBD1
23 Aug 2019
24 Jul 2020
11 Nov 2020
Deferred Share Rights – FY2022 EIP1
Share Rights - LTIP
Share Rights - LTIP
Deferred Share Rights - STIP3
—
496,171
—
405,655
—
243,198
—
304,213
—
—
983,204
1,510,476
327,269
4,270,186
—
01 Jul 2023
—
01 Jul 2023
—
01 Jul 2023
—
01 Jul 2023
—
—
30 Jun 2022
30 Jun 2023
01 Jul 2023
199,892
16,126
109,007
13,184
71,992
7,904
87,197
9,887
70,278
96,773
—
32,727
10,636
725,603
1 Share rights as part of the FY2022 EIP are expected to be granted during FY2023. The number of rights to be granted is determined based on Central
Petroleum’s share price for the 20 days after release of the June 2022 quarterly report, which is calculated as 9.9 cents per right.
2 The maximum value of the share rights yet to vest has been determined as the amount of the grant date fair value of the rights that is yet to be expensed.
For the FY2022 EIP, the maximum value yet to vest was estimated based on the share price at 30 June 2022. The minimum value to vest is nil, as the rights
will be forfeited if the vesting conditions are not met.
3 The FY2020 STIP was awarded as rights to deferred shares instead of cash.
Table 8: Options Holdings of Key Management Personnel
Number of
Options Held
at Start of
Year
Options
Granted as
Compensation
Exercise
Price
Expiry
Date
Cancelled or
Expired
During the
Year
Exercised and
Converted to
Shares
Retained on
Departure
Number of
Options Held
at End of Year
(Unvested)
Share Options
Key Management Personnel
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson1
Total
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
5,105,000
5,105,000
4,170,025
4,170,025
2,750,000
2,750,000
3,333,333
3,333,333
N/A
2,792,758
15,358,358
18,151,116
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
(2,792,758)
5,105,000
5,105,000
4,170,025
4,170,025
2,750,000
2,750,000
3,333,333
3,333,333
N/A
N/A
—
(2,792,758)
15,358,358
15,358,358
1 Robin Polson resigned 30 June 2021. 930,070 options were cancelled post departure.
J. Remuneration Details – Statutory tables (continued)
Table 9: Shareholdings of Key Management Personnel
Held at
Beginning of
Held at
Date of
Year
Appointment
SPP & On
Market
Purchase
Exercise of
Rights
Net
Change
Other
Held at
Date of
Departure
Held at
End of
Year
Ordinary Shares
Non-Executive Directors
Stuart Baker
Julian Fowles1
Stephen Gardiner2
Wrixon Gasteen3
Katherine Hirschfeld
Agu Kantsler
Michael McCormack4
Sub-total
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson5
Jonathan Snape6
Daniel White
Sub-total
Total KMP
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
Other Key Management Personnel
—
—
N/A
100,000
N/A
N/A
N/A
793,337
760,850
760,850
—
—
—
N/A
760,850
1,654,187
2,606,757
2,606,757
140,845
140,845
141,000
141,000
—
—
N/A
94,598
N/A
N/A
2,309,074
2,309,074
5,197,676
5,292,274
5,958,526
6,946,461
N/A
N/A
N/A
N/A
—
N/A
N/A
N/A
N/A
N/A
—
—
—
—
—
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
—
N/A
N/A
N/A
—
—
—
—
1 Julian Fowles resigned 31 October 2020.
2 Stephen Gardiner was appointed 1 July 2021.
3 Wrixon Gasteen resigned 28 November 2020.
4 Michael McCormack was appointed Director on 1 September 2020.
5 Robin Polson resigned 30 June 2021.
6
Jonathan Snape commenced 1 July 2021.
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
245,339
253,569
498,908
498,908
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(893,337)
760,850
760,850
(100,000)
(793,337)
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
—
(94,598)
(94,598)
—
(987,935)
—
—
N/A
N/A
—
N/A
N/A
N/A
—
—
—
—
760,850
760,850
2,606,757
2,606,757
386,184
140,845
141,000
141,000
—
—
N/A
N/A
—
N/A
2,562,643
2,309,074
5,696,584
5,197,676
6,457,434
5,958,526
46
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 47
REMUNERATION REPORT
(AUDITED)
J. Remuneration Details – Statutory tables (continued)
The number of Options to ordinary shares in the Company under the Executive Share Option Plan held during the financial year by key
management personnel of the Consolidated Entity, including their personally related parties, are set out below:
Table 7: Vesting profile of Share Rights Holdings of Key Management Personnel
Grant Date
Type
Key Management Personnel
Leon Devaney
11 Nov 2020
Deferred Share Rights – STIP3
496,171
01 Jul 2023
11 Nov 2020
Deferred Share Rights - STIP3
405,655
01 Jul 2023
TBD1
TBD1
TBD1
Deferred Share Rights – FY2022 EIP1
Deferred Share Rights – FY2022 EIP1
Deferred Share Rights – FY2022 EIP1
11 Nov 2020
Deferred Share Rights - STIP3
243,198
01 Jul 2023
Duncan Lockhart
TBD1
Deferred Share Rights – FY2022 EIP1
11 Nov 2020
Deferred Share Rights - STIP3
304,213
01 Jul 2023
Maximum Number
of Unvested Rights
at 30 June 2022
Vesting Date
Maximum value
yet to vest2
—
—
—
—
—
—
—
—
—
—
—
—
983,204
1,510,476
327,269
4,270,186
30 Jun 2022
30 Jun 2023
01 Jul 2023
199,892
16,126
109,007
13,184
71,992
7,904
87,197
9,887
70,278
96,773
—
32,727
10,636
725,603
TBD1
TBD1
23 Aug 2019
24 Jul 2020
11 Nov 2020
Deferred Share Rights – FY2022 EIP1
Deferred Share Rights – FY2022 EIP1
Share Rights - LTIP
Share Rights - LTIP
Deferred Share Rights - STIP3
Ross Evans
Damian Galvin
Jonathan Snape
Daniel White
Total
1 Share rights as part of the FY2022 EIP are expected to be granted during FY2023. The number of rights to be granted is determined based on Central
Petroleum’s share price for the 20 days after release of the June 2022 quarterly report, which is calculated as 9.9 cents per right.
2 The maximum value of the share rights yet to vest has been determined as the amount of the grant date fair value of the rights that is yet to be expensed.
For the FY2022 EIP, the maximum value yet to vest was estimated based on the share price at 30 June 2022. The minimum value to vest is nil, as the rights
will be forfeited if the vesting conditions are not met.
3 The FY2020 STIP was awarded as rights to deferred shares instead of cash.
Table 8: Options Holdings of Key Management Personnel
Number of
Options Held
at Start of
Options
Granted as
Exercise
Year
Compensation
Price
Expiry
Date
During the
Converted to
Retained on
at End of Year
Year
Shares
Departure
(Unvested)
Cancelled or
Expired
Exercised and
Number of
Options Held
Share Options
Key Management Personnel
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson1
Total
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
5,105,000
5,105,000
4,170,025
4,170,025
2,750,000
2,750,000
3,333,333
3,333,333
N/A
2,792,758
15,358,358
18,151,116
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
5,105,000
5,105,000
4,170,025
4,170,025
2,750,000
2,750,000
3,333,333
3,333,333
N/A
N/A
(2,792,758)
—
(2,792,758)
15,358,358
15,358,358
1 Robin Polson resigned 30 June 2021. 930,070 options were cancelled post departure.
J. Remuneration Details – Statutory tables (continued)
Table 9: Shareholdings of Key Management Personnel
Held at
Beginning of
Year
Held at
Date of
Appointment
SPP & On
Market
Purchase
Exercise of
Rights
Net
Change
Other
Held at
Date of
Departure
Held at
End of
Year
Ordinary Shares
Non-Executive Directors
Stuart Baker
2022
2021
Julian Fowles1
Stephen Gardiner2
Wrixon Gasteen3
Katherine Hirschfeld
Agu Kantsler
Michael McCormack4
Sub-total
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
—
—
N/A
100,000
N/A
N/A
N/A
793,337
760,850
760,850
—
—
—
N/A
760,850
1,654,187
Other Key Management Personnel
Leon Devaney
2022
2021
2,606,757
2,606,757
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson5
Jonathan Snape6
Daniel White
Sub-total
Total KMP
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
2022
2021
140,845
140,845
141,000
141,000
—
—
N/A
94,598
N/A
N/A
2,309,074
2,309,074
5,197,676
5,292,274
5,958,526
6,946,461
N/A
N/A
N/A
N/A
—
N/A
N/A
N/A
N/A
N/A
—
—
—
—
—
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
—
N/A
N/A
N/A
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
245,339
—
—
—
—
—
—
—
—
—
253,569
—
498,908
—
498,908
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
N/A
N/A
N/A
(100,000)
N/A
N/A
N/A
(793,337)
N/A
N/A
N/A
N/A
N/A
N/A
—
—
N/A
N/A
—
N/A
N/A
N/A
760,850
760,850
—
—
—
—
N/A
(893,337)
760,850
760,850
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
(94,598)
N/A
N/A
N/A
N/A
—
(94,598)
—
(987,935)
2,606,757
2,606,757
386,184
140,845
141,000
141,000
—
—
N/A
N/A
—
N/A
2,562,643
2,309,074
5,696,584
5,197,676
6,457,434
5,958,526
1 Julian Fowles resigned 31 October 2020.
2 Stephen Gardiner was appointed 1 July 2021.
3 Wrixon Gasteen resigned 28 November 2020.
4 Michael McCormack was appointed Director on 1 September 2020.
5 Robin Polson resigned 30 June 2021.
6
Jonathan Snape commenced 1 July 2021.
46
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 47
REMUNERATION REPORT
(AUDITED)
K. Executive Service Agreements
The details of service agreements of the key management personnel of the Consolidated Entity as of 1 July 2022 are as follows:
Table 10: Key Management Personnel Service Agreements
Name
Position
Term of agreement
expires
Total Annual Fixed
Remuneration1
Notice period 2
Leon Devaney
Managing Director & Chief Executive Officer
Full time permanent
Ross Evans
Chief Operations Officer
Damian Galvin
Duncan Lockhart
Chief Financial Officer
General Manager Exploration3
Jonathan Snape
Chief Commercial Officer
01 Dec 2022
Full time permanent
08 Jul 2022
Full time permanent
Daniel White
Group General Counsel & Company Secretary
Full time permanent
$654,572
$535,557
$353,926
$409,450
$345,514
$475,523
6-months
6-months
6-months
6-months
3-months
3-months
1 Total Annual Fixed Remuneration, effective 1 July 2022 includes compulsory superannuation contributions.
2
In certain exceptional circumstances (such as breach or gross misconduct) a shorter notice period applies.
3 Duncan Lockhart resigned effective 31 August 2022.
If the employment of a member of key management personnel listed above is terminated within 12-months of a change of control event,
the executive is entitled to a termination payment equivalent to 12-months TFR (reduced by any redundancy entitlement received).
L. Non-Executive Director Fee Arrangements
The Company has engaged all Directors pursuant to written service agreements. The terms of appointment are subject to the Company’s
constitution. The Company maintains an appropriate level of Directors’ and Officers’ Liability Insurance and provide rights relating to
indemnity, insurance, and access to documents.
The table below summarises the Non-Executive Director fees for FY2022. Directors had the discretion to sacrifice up to 25% of their FY22
Base Fee to earn Share Rights. The issue of Share Rights to Directors was approved under ASX Listing Rule 10.14 at the Company’s Annual
General Meeting held on 10 November 2021.
Board Fees (per annum)
Chair
Non-Executive Director
$130,000
$70,000
FY2022 Committee Fees (per annum)
Audit & Financial Risk
Remuneration & Nominations
Risk & Sustainability
Chair
Member
Chair
Member
Chair
Member
$10,000
$5,000
$10,000
$5,000
$10,000
$5,000
The directors also receive superannuation benefits in accordance with legislative requirements.
Signed in accordance with a resolution of the directors:
Michael McCormack
Chair
16 September 2022
AUDITOR’S INDEPENDENCE DECLARATION
30 JUNE 2022
Auditor’s Independence Declaration
As lead auditor for the audit of Central Petroleum Limited for the year ended 30 June 2022, I declare
that to the best of my knowledge and belief, there have been:
(a) no contraventions of the auditor independence requirements of the Corporations Act 2001
in relation to the audit; and
(b) no contraventions of any applicable code of professional conduct in relation to the audit.
This declaration is in respect of Central Petroleum Limited and the entities it controlled during the
period.
Marcus Goddard
Partner
PricewaterhouseCoopers
Brisbane
16 September 2022
PricewaterhouseCoopers, ABN 52 780 433 757
480 Queen Street, BRISBANE QLD 4000, GPO Box 150, BRISBANE QLD 4001
T: +61 7 3257 5000, F: +61 7 3257 5999
Liability limited by a scheme approved under Professional Standards Legislation
48
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 49
REMUNERATION REPORT
(AUDITED)
K. Executive Service Agreements
The details of service agreements of the key management personnel of the Consolidated Entity as of 1 July 2022 are as follows:
Table 10: Key Management Personnel Service Agreements
Name
Position
Term of agreement
Total Annual Fixed
expires
Remuneration1
Notice period 2
Leon Devaney
Managing Director & Chief Executive Officer
Full time permanent
Ross Evans
Chief Operations Officer
Damian Galvin
Chief Financial Officer
Duncan Lockhart
General Manager Exploration3
Jonathan Snape
Chief Commercial Officer
01 Dec 2022
Full time permanent
08 Jul 2022
Full time permanent
Daniel White
Group General Counsel & Company Secretary
Full time permanent
$654,572
$535,557
$353,926
$409,450
$345,514
$475,523
6-months
6-months
6-months
6-months
3-months
3-months
1 Total Annual Fixed Remuneration, effective 1 July 2022 includes compulsory superannuation contributions.
2
In certain exceptional circumstances (such as breach or gross misconduct) a shorter notice period applies.
3 Duncan Lockhart resigned effective 31 August 2022.
If the employment of a member of key management personnel listed above is terminated within 12-months of a change of control event,
the executive is entitled to a termination payment equivalent to 12-months TFR (reduced by any redundancy entitlement received).
L. Non-Executive Director Fee Arrangements
The Company has engaged all Directors pursuant to written service agreements. The terms of appointment are subject to the Company’s
constitution. The Company maintains an appropriate level of Directors’ and Officers’ Liability Insurance and provide rights relating to
indemnity, insurance, and access to documents.
The table below summarises the Non-Executive Director fees for FY2022. Directors had the discretion to sacrifice up to 25% of their FY22
Base Fee to earn Share Rights. The issue of Share Rights to Directors was approved under ASX Listing Rule 10.14 at the Company’s Annual
General Meeting held on 10 November 2021.
Board Fees (per annum)
Chair
Non-Executive Director
$130,000
$70,000
FY2022 Committee Fees (per annum)
Audit & Financial Risk
Remuneration & Nominations
Risk & Sustainability
Chair
$10,000
Member
$5,000
Chair
$10,000
Member
$5,000
Chair
$10,000
Member
$5,000
The directors also receive superannuation benefits in accordance with legislative requirements.
Signed in accordance with a resolution of the directors:
Michael McCormack
Chair
16 September 2022
AUDITOR’S INDEPENDENCE DECLARATION
30 JUNE 2022
Auditor’s Independence Declaration
As lead auditor for the audit of Central Petroleum Limited for the year ended 30 June 2022, I declare
that to the best of my knowledge and belief, there have been:
(a) no contraventions of the auditor independence requirements of the Corporations Act 2001
in relation to the audit; and
(b) no contraventions of any applicable code of professional conduct in relation to the audit.
This declaration is in respect of Central Petroleum Limited and the entities it controlled during the
period.
Marcus Goddard
Partner
PricewaterhouseCoopers
Brisbane
16 September 2022
48
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 49
PricewaterhouseCoopers, ABN 52 780 433 757
480 Queen Street, BRISBANE QLD 4000, GPO Box 150, BRISBANE QLD 4001
T: +61 7 3257 5000, F: +61 7 3257 5999
Liability limited by a scheme approved under Professional Standards Legislation
FINANCIAL REPORT
CONSOLIDATED STATEMENT OF COMPREHENSIVE
CONTENTS
FINANCIAL STATEMENTS
Consolidated Statement of Comprehensive Income .......................................................................................... 51
Consolidated Balance Sheet ........................................................................................................................................ 52
Consolidated Statement of Changes in Equity ....................................................................................................53
Consolidated Statement of Cash Flows ................................................................................................................. 54
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS ................................................................................55
DIRECTORS’ DECLARATION ................................................................................................................................................ 96
INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS ........................................................................................ 97
These Financial Statements are the consolidated financial statements of the Group, consisting of Central Petroleum Limited and its
subsidiaries.
The Financial Statements are presented in Australian currency.
Central Petroleum Limited is a company limited by shares, incorporated and domiciled in Australia. Its registered office and principal place
of business is:
Level 7, 369 Ann Street
Brisbane, Queensland 4000
A description of the nature of the Consolidated Entity’s operations and its principal activities is included in the operating and financial
review on pages 3 to 26. These pages are not part of these financial statements.
The financial statements were authorised for issue by the Directors on 16 September 2022. The Directors have the power to amend and
Earnings per share for profit or loss attributable to the ordinary equity
reissue the financial statements.
Through the use of the internet, we have ensured that our corporate reporting is timely and complete. ASX releases, financial reports and
other information are available via the links on our website: www.centralpetroleum.com.au.
holders of the company:
Basic earnings per share (cents)
Diluted earnings per share (cents)
INCOME
FOR THE YEAR ENDED 30 JUNE 2022
Revenue from contracts with customers – sale of hydrocarbons
Cost of sales
Gross profit
Other income
Exploration expenditure
Employee benefits and associated costs net of recoveries
Share based employment benefits
General and administrative expenses net of recoveries
Depreciation and amortisation
Finance costs
Profit before income tax
Income tax expense
Profit for the year
Other comprehensive profit/(loss) for the year, net of tax
Total comprehensive profit for the year
Total comprehensive profit attributable to members of the parent entity
NOTE
2
3
4(b)
32(f)
4(a)
4(a)
5
23
23
2022
$’000
42,151
(21,257)
20,894
37,300
(21,647)
(1,594)
(1,524)
(1,043)
(6,779)
(4,287)
21,320
21,320
—
—
21,320
21,320
2.94
2.88
2021
$’000
59,827
(28,852)
30,975
155
(7,739)
(2,180)
(1,862)
(924)
(12,503)
(5,671)
251
—
251
—
251
251
0.03
0.03
50
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
51
The accompanying notes form part of these financial statements.
FINANCIAL REPORT
CONTENTS
FINANCIAL STATEMENTS
Consolidated Statement of Comprehensive Income .......................................................................................... 51
Consolidated Balance Sheet ........................................................................................................................................ 52
Consolidated Statement of Changes in Equity ....................................................................................................53
Consolidated Statement of Cash Flows ................................................................................................................. 54
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS ................................................................................55
DIRECTORS’ DECLARATION ................................................................................................................................................ 96
INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS ........................................................................................ 97
These Financial Statements are the consolidated financial statements of the Group, consisting of Central Petroleum Limited and its
subsidiaries.
The Financial Statements are presented in Australian currency.
of business is:
Level 7, 369 Ann Street
Brisbane, Queensland 4000
Central Petroleum Limited is a company limited by shares, incorporated and domiciled in Australia. Its registered office and principal place
A description of the nature of the Consolidated Entity’s operations and its principal activities is included in the operating and financial
review on pages 3 to 26. These pages are not part of these financial statements.
The financial statements were authorised for issue by the Directors on 16 September 2022. The Directors have the power to amend and
reissue the financial statements.
CONSOLIDATED STATEMENT OF COMPREHENSIVE
INCOME
FOR THE YEAR ENDED 30 JUNE 2022
Revenue from contracts with customers – sale of hydrocarbons
Cost of sales
Gross profit
Other income
Exploration expenditure
Employee benefits and associated costs net of recoveries
Share based employment benefits
General and administrative expenses net of recoveries
Depreciation and amortisation
Finance costs
Profit before income tax
Income tax expense
Profit for the year
Other comprehensive profit/(loss) for the year, net of tax
Total comprehensive profit for the year
Total comprehensive profit attributable to members of the parent entity
Earnings per share for profit or loss attributable to the ordinary equity
holders of the company:
Through the use of the internet, we have ensured that our corporate reporting is timely and complete. ASX releases, financial reports and
other information are available via the links on our website: www.centralpetroleum.com.au.
Basic earnings per share (cents)
Diluted earnings per share (cents)
NOTE
2
3
4(b)
32(f)
4(a)
4(a)
5
23
23
2022
$’000
42,151
(21,257)
20,894
37,300
(21,647)
(1,594)
(1,524)
(1,043)
(6,779)
(4,287)
21,320
—
21,320
—
21,320
21,320
2.94
2.88
2021
$’000
59,827
(28,852)
30,975
155
(7,739)
(2,180)
(1,862)
(924)
(12,503)
(5,671)
251
—
251
—
251
251
0.03
0.03
50
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
51
The accompanying notes form part of these financial statements.
CONSOLIDATED BALANCE SHEET
AS AT 30 JUNE 2022
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEAR ENDED 30 JUNE 2022
Contributed
Equity
$’000
Reserves
$’000
Accumulated
Losses
$’000
Balance at 1 July 2020
197,776
27,238
(223,432)
Total profit for the year
Other comprehensive loss
Total comprehensive loss for the year
Transactions with owners in their capacity
as owners
Share based payments
Share issue costs
Total profit for the year
Other comprehensive loss
Total comprehensive loss for the year
Transactions with owners in their capacity
as owners
Share based payments
Share issue costs
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,862
(6)
1,856
1,524
(3)
1,521
251
—
251
—
—
—
21,320
—
21,320
—
—
—
Balance at 30 June 2021
197,776
29,094
(223,181)
Total
$’000
1,582
251
—
251
1,862
(6)
1,856
3,689
21,320
—
21,320
1,524
(3)
1,521
Balance at 30 June 2022
197,776
30,615
(201,861)
26,530
NOTE
2022
$’000
ASSETS
Current assets
Cash and cash equivalents
Trade and other receivables
Inventories
Assets classified as held for sale
Total current assets
Non-current assets
Property, plant and equipment
Right of use assets
Exploration assets
Intangible assets
Other financial assets
Goodwill
Total non-current assets
Total assets
LIABILITIES
Current liabilities
Trade and other payables
Deferred revenue
Borrowings
Lease liabilities
Provisions
Liabilities directly associated with assets classified as held for sale
Total current liabilities
Non-current liabilities
Deferred revenue
Borrowings
Lease liabilities
Provisions
Total non-current liabilities
Total liabilities
Net assets
EQUITY
Contributed equity
Reserves
Accumulated losses
Total equity
7
8
9
10
11
12
13
14
15
16
17
2(b)
18(a)
12
19
10
2(b)
18(b)
12
19
20 (a)
21
22
2021
$’000
37,159
7,111
1,621
57,968
103,859
53,988
1,455
8,397
302
4,218
1,953
70,313
21,647
26,872
3,868
—
52,387
53,846
922
8,397
379
4,410
1,953
69,907
122,294
174,172
13,526
5,309
4,500
413
6,325
—
30,073
13,614
26,309
588
25,180
65,691
95,764
26,530
197,776
30,615
(201,861)
26,530
10,491
5,244
36,000
517
3,918
39,436
95,606
15,697
30,809
992
27,379
74,877
170,483
3,689
197,776
29,094
(223,181)
3,689
The accompanying notes form part of these financial statements.
The accompanying notes form part of these financial statements.
52
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
53
CONSOLIDATED BALANCE SHEET
AS AT 30 JUNE 2022
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEAR ENDED 30 JUNE 2022
Contributed
Equity
$’000
Reserves
$’000
Accumulated
Losses
$’000
Balance at 1 July 2020
197,776
27,238
(223,432)
Total profit for the year
Other comprehensive loss
Total comprehensive loss for the year
Transactions with owners in their capacity
as owners
Share based payments
Share issue costs
—
—
—
—
—
—
—
—
—
1,862
(6)
1,856
251
—
251
—
—
—
Balance at 30 June 2021
197,776
29,094
(223,181)
Total profit for the year
Other comprehensive loss
Total comprehensive loss for the year
Transactions with owners in their capacity
as owners
Share based payments
Share issue costs
—
—
—
—
—
—
—
—
—
1,524
(3)
1,521
21,320
—
21,320
—
—
—
Total
$’000
1,582
251
—
251
1,862
(6)
1,856
3,689
21,320
—
21,320
1,524
(3)
1,521
Liabilities directly associated with assets classified as held for sale
Balance at 30 June 2022
197,776
30,615
(201,861)
26,530
ASSETS
Current assets
Cash and cash equivalents
Trade and other receivables
Inventories
Assets classified as held for sale
Total current assets
Non-current assets
Property, plant and equipment
Right of use assets
Exploration assets
Intangible assets
Other financial assets
Goodwill
Total non-current assets
Total assets
LIABILITIES
Current liabilities
Trade and other payables
Deferred revenue
Borrowings
Lease liabilities
Provisions
Total current liabilities
Non-current liabilities
Deferred revenue
Borrowings
Lease liabilities
Provisions
Total non-current liabilities
Total liabilities
Net assets
EQUITY
Contributed equity
Reserves
Accumulated losses
Total equity
122,294
174,172
NOTE
2022
$’000
7
8
9
10
11
12
13
14
15
16
17
2(b)
18(a)
12
19
10
2(b)
18(b)
12
19
20 (a)
21
22
21,647
26,872
3,868
—
52,387
53,846
922
8,397
379
4,410
1,953
69,907
13,526
5,309
4,500
413
6,325
—
30,073
13,614
26,309
588
25,180
65,691
95,764
26,530
197,776
30,615
(201,861)
26,530
2021
$’000
37,159
7,111
1,621
57,968
103,859
53,988
1,455
8,397
302
4,218
1,953
70,313
10,491
5,244
36,000
517
3,918
39,436
95,606
15,697
30,809
992
27,379
74,877
170,483
3,689
197,776
29,094
(223,181)
3,689
The accompanying notes form part of these financial statements.
The accompanying notes form part of these financial statements.
52
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
53
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
Cash flows from operating activities
Receipts from customers
Interest received
Other income
Government grants
Interest and borrowing costs
Payments for exploration expenditure
Payments to other suppliers and employees
Net cash inflow from operating activities
Cash flows from investing activities
Payments for property, plant and equipment
Proceeds from sale of producing assets, and property, plant and equipment
Proceeds and deposits for the disposal of exploration permits
Lodgement of security deposits and bonds
Net cash inflow/(outflow) from investing activities
Cash flows from financing activities
Payments for the issue of securities
Repayment of borrowings
Transaction costs related to borrowings
Principal elements of lease payments
Net cash outflow from financing activities
Net (decrease)/increase in cash and cash equivalents
Cash and cash equivalents at the beginning of the financial year
NOTE
28
3(a)
29(b)
29(b)
2022
$’000
44,333
59
42
11
(2,472)
(10,121)
(28,212)
3,640
(10,791)
28,305
—
(108)
17,406
(3)
(36,000)
—
(561)
(36,564)
(15,518)
37,165
Cash and cash equivalents at the end of the financial year
7
21,647
2021
$’000
65,539
82
73
1,367
(3,924)
(5,461)
(33,540)
24,136
(6,489)
9
—
(1,562)
(8,042)
(5)
(4,000)
(220)
(622)
(4,847)
11,247
25,918
37,165
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The principal accounting policies adopted in the preparation of these consolidated financial statements are set out below. These policies
have been consistently applied to all the years presented, unless otherwise stated. The financial statements are for the consolidated entity
consisting of Central Petroleum Limited (“the Company”) and its subsidiaries (collectively “the Group” or “the Consolidated Entity”).
(a) Basis of Preparation
These general-purpose financial statements have been prepared in accordance with Australian Accounting Standards and Interpretations
issued by the Australian Accounting Standards Board and the Corporations Act 2001. They present reclassified comparative information
where required for consistency with the current year’s presentation or where otherwise stated. Central Petroleum Limited is a for-profit
entity for the purpose of preparing the financial statements.
Rounding of Amounts
The company is of a kind referred to in ASIC Legislative Instrument 2016/191, relating to the ‘rounding off’ of amounts in the financial
statements. Amounts in the financial statements have been rounded off in accordance with the instrument to the nearest thousand
dollars, or in certain cases, the nearest dollar.
(i)
Going Concern
The Directors have prepared the financial statements on a going concern basis which contemplates continuity of normal business activities
and the realisation of assets and settlement of liabilities in the normal course of business.
(ii) Compliance with IFRS
The consolidated financial statements of the Central Petroleum Limited Group also comply with International Financial Reporting Standards
(IFRS) as issued by the International Accounting Standards Board.
(iii) Early Adoption of Standards
The Group has not applied any pronouncements to the annual reporting period beginning on 1 July 2021 where such application would
result in them being applied prior to them becoming mandatory.
(iv) Historical Cost Convention
These financial statements have been prepared under the historical cost convention.
(v) Critical Accounting Judgements and Key Sources of Estimate Uncertainty
In the application of the Group’s accounting policies, management is required to make judgements, estimates and assumptions regarding
carrying values of assets and liabilities that are not readily apparent from other sources. The estimates and assumptions are based on
historical experience and various other factors that are believed to be reasonable under the circumstances, the results of which form the
basis of making the judgements. Actual results may differ from these estimates. Key judgements in applying the entity’s accounting policies
are required in the following areas:
Rehabilitation Obligations
The Group recognises any obligations for removal and restoration that are incurred during a particular period as a consequence of having
undertaken exploration and evaluation activity. The Group makes provision for future restoration expenditure relating to work previously
undertaken based on management’s estimation of the work required and by obtaining cost estimates from relevant experts. Further
information on the nature and carrying amount of restoration and rehabilitation obligations can be found in Note 19.
Share-based Payments
The Group is required to use assumptions in respect of its fair value models, and the variable elements in these models, used in attributing
a value to share based payments. The Directors have used a model to value options and rights, which requires estimates and judgements
to quantify the inputs used by the model. Further information on the assumptions used in determining the fair value of rights and options
granted during the year can be found in Section I of the Remuneration Report.
The accompanying notes form part of these financial statements.
54
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
55
Cash flows from operating activities
Receipts from customers
Interest received
Other income
Government grants
Interest and borrowing costs
Payments for exploration expenditure
Payments to other suppliers and employees
Net cash inflow from operating activities
28
Cash flows from investing activities
Payments for property, plant and equipment
Proceeds from sale of producing assets, and property, plant and equipment
3(a)
Proceeds and deposits for the disposal of exploration permits
Lodgement of security deposits and bonds
Net cash inflow/(outflow) from investing activities
Cash flows from financing activities
Payments for the issue of securities
Repayment of borrowings
Transaction costs related to borrowings
Principal elements of lease payments
Net cash outflow from financing activities
Net (decrease)/increase in cash and cash equivalents
Cash and cash equivalents at the beginning of the financial year
29(b)
29(b)
2022
$’000
44,333
59
42
11
(2,472)
(10,121)
(28,212)
3,640
(10,791)
28,305
—
(108)
17,406
(3)
(36,000)
—
(561)
(36,564)
(15,518)
37,165
2021
$’000
65,539
82
73
1,367
(3,924)
(5,461)
(33,540)
24,136
(6,489)
9
—
(1,562)
(8,042)
(5)
(4,000)
(220)
(622)
(4,847)
11,247
25,918
37,165
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTE
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The principal accounting policies adopted in the preparation of these consolidated financial statements are set out below. These policies
have been consistently applied to all the years presented, unless otherwise stated. The financial statements are for the consolidated entity
consisting of Central Petroleum Limited (“the Company”) and its subsidiaries (collectively “the Group” or “the Consolidated Entity”).
(a) Basis of Preparation
These general-purpose financial statements have been prepared in accordance with Australian Accounting Standards and Interpretations
issued by the Australian Accounting Standards Board and the Corporations Act 2001. They present reclassified comparative information
where required for consistency with the current year’s presentation or where otherwise stated. Central Petroleum Limited is a for-profit
entity for the purpose of preparing the financial statements.
Rounding of Amounts
The company is of a kind referred to in ASIC Legislative Instrument 2016/191, relating to the ‘rounding off’ of amounts in the financial
statements. Amounts in the financial statements have been rounded off in accordance with the instrument to the nearest thousand
dollars, or in certain cases, the nearest dollar.
(i)
Going Concern
The Directors have prepared the financial statements on a going concern basis which contemplates continuity of normal business activities
and the realisation of assets and settlement of liabilities in the normal course of business.
(ii) Compliance with IFRS
The consolidated financial statements of the Central Petroleum Limited Group also comply with International Financial Reporting Standards
(IFRS) as issued by the International Accounting Standards Board.
(iii) Early Adoption of Standards
The Group has not applied any pronouncements to the annual reporting period beginning on 1 July 2021 where such application would
result in them being applied prior to them becoming mandatory.
(iv) Historical Cost Convention
These financial statements have been prepared under the historical cost convention.
Cash and cash equivalents at the end of the financial year
7
21,647
(v) Critical Accounting Judgements and Key Sources of Estimate Uncertainty
In the application of the Group’s accounting policies, management is required to make judgements, estimates and assumptions regarding
carrying values of assets and liabilities that are not readily apparent from other sources. The estimates and assumptions are based on
historical experience and various other factors that are believed to be reasonable under the circumstances, the results of which form the
basis of making the judgements. Actual results may differ from these estimates. Key judgements in applying the entity’s accounting policies
are required in the following areas:
Rehabilitation Obligations
The Group recognises any obligations for removal and restoration that are incurred during a particular period as a consequence of having
undertaken exploration and evaluation activity. The Group makes provision for future restoration expenditure relating to work previously
undertaken based on management’s estimation of the work required and by obtaining cost estimates from relevant experts. Further
information on the nature and carrying amount of restoration and rehabilitation obligations can be found in Note 19.
Share-based Payments
The Group is required to use assumptions in respect of its fair value models, and the variable elements in these models, used in attributing
a value to share based payments. The Directors have used a model to value options and rights, which requires estimates and judgements
to quantify the inputs used by the model. Further information on the assumptions used in determining the fair value of rights and options
granted during the year can be found in Section I of the Remuneration Report.
The accompanying notes form part of these financial statements.
54
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
55
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(a) Basis of Preparation (continued)
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 lease itself or, if not, whether it successfully recovers the related exploration and evaluation expenditure
through sale. Factors that impact recoverability may include, but are not limited to, the level of resources and reserves, the cost of
production, regulatory changes and commodity price movements. Ongoing exploration and evaluation expenditure is expensed as
incurred. Acquisition expenditure is capitalised if activities in the area of interest have not yet reached a stage that permits a reasonable
assessment of the existence or otherwise of economically recoverable reserves. To the extent that the capitalised acquisition expenditure
is determined not to be recoverable in future, profits and net assets will be reduced in the period in which this determination is made.
Further information on the carrying value of capitalised exploration and evaluation expenditure can be found in Note 13.
Other Non-financial Assets
Property, plant and equipment and other non-financial assets are written down immediately to their recoverable amount if the asset’s
carrying amount is greater than its estimated recoverable amount. Goodwill is tested for impairment annually or whenever events or
changes in circumstances indicate that the carrying amount may not be recoverable. For the purposes of assessing impairment, assets are
grouped at the lowest levels for which there are separately identifiable cash inflows which are largely independent of the cash inflows from
other assets or groups of assets (cash-generating units). Where discounted cash flows are used to assess recoverability of non-financial
assets, the Group is required to use assumptions in respect of future commodity prices, foreign exchange rates, interest rates and
operating costs, along with the possible impact of climate-related and other emerging business risks in determining expected future cash
flows from operations. Further information on the nature and carrying value of other non-financial assets can be found in Notes 11, 12, 14
and 16. Testing for impairment of goodwill and other non-financial assets in FY2022 was assessed against a recent market transaction
(refer Note 3(a)).
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 Balance Sheet. Deferred tax assets, including those arising from un-recouped tax losses and capital losses,
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 Balance Sheet and the amount of other tax losses and temporary
differences not yet recognised. In such circumstances, some or all of the carrying amounts of recognised deferred tax assets and liabilities
may require adjustment, resulting in a corresponding credit or charge to the Consolidated Statement of Profit or Loss and Other
Comprehensive Income.
(b) Principles of Consolidation
(i)
Subsidiaries
The consolidated financial statements incorporate the assets and liabilities of all subsidiaries of Central Petroleum Limited (“the Company”
or “Parent Entity”) as at 30 June and the results of all subsidiaries for the year then ended. Central Petroleum Limited and its subsidiaries
together are referred to in this financial report as “the Group” or “the Consolidated Entity”.
Subsidiaries are all entities (including structured entities) over which the Group has control. The Group controls an entity when the Group
is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its
power to direct the activities of the entity.
Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated from the date that
control ceases. The acquisition method is used to account for business combinations by the Group.
Intercompany transactions, balances and unrealised gains on transactions between Group entities are eliminated. Unrealised losses are
also eliminated unless the transaction provides evidence of the impairment of the asset transferred. Accounting policies of subsidiaries
have been changed where necessary to ensure consistency with the policies adopted by the Group.
Non-controlling interests (if applicable) in the results and equity of subsidiaries are shown separately in the statement of comprehensive
income, statement of changes in equity and balance sheet respectively.
(b) Principles of Consolidation (continued)
(ii)
Joint Arrangements
The Group’s investments in joint arrangements are classified as either joint operations or joint ventures; depending on the contractual
rights and obligations each investor has, rather than the legal structure of the joint arrangement.
The Group’s exploration and production activities are conducted through joint arrangements governed by joint operating agreements or
similar contractual relationships.
A joint operation involves the joint control, and often the joint ownership, of one or more assets contributed to, or acquired for the
purpose of, the joint operation and dedicated to the purposes of the joint operation. The assets are used to obtain benefits for the parties
to the joint operation. Each party may take a share of the output from the assets and each bears an agreed share of expenses incurred.
Each party has control over its share of future economic benefits through its share of the joint operation. The interests of the Group in joint
operations are brought to account by recognising in the financial statements the Group’s share of jointly controlled assets, share of
expenses and liabilities incurred, and the income from the sale or use of its share of the production of the joint operation in accordance
with the revenue policy in Note 1(e). Details of the joint operations are set out in Note 35.
(c) Segment Reporting
Operating segments are reported in Note 24 in a manner consistent with the internal reporting provided to the chief operating decision
makers. The chief operating decision makers, who are responsible for allocating resources and assessing performance of the operating
segments, have been identified as the Executive Management Team.
(d) Foreign Currency Translation
(i)
Functional and Presentation Currency
Items included in the financial statements of each of the Group’s entities are measured using the currency of the primary economic
environment in which the entity operates (the “functional currency”). The consolidated financial statements are presented in Australian
dollars, which is Central Petroleum Limited’s functional currency and presentation currency.
(ii)
Transactions and Balances
Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the
transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end
exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in profit or loss, except when they are
deferred in equity as qualifying cash flow hedges and qualifying net investment hedges or are attributable to part of the net investment in
a foreign operation.
(e) Revenue Recognition
Revenue from contracts with customers is recognised in the income statement when or as the Group transfers control of goods or services
to a customer at the amount to which the Group expects to be entitled. If the consideration promised includes a variable amount, the
Group estimates the amount of consideration to which it will be entitled.
(i)
Revenue from the sale of hydrocarbons
Revenue from the sale of hydrocarbons is recognised based on volumes sold under contracts with customers, at the point in time where
performance obligations are considered met. Generally, regarding the sale of hydrocarbon products, the performance obligation will be
met when the product is delivered to the specified measurement point (gas) or point of loading/unloading (liquids).
(ii)
Farmouts and terminations
Farmouts outside the exploration phase are accounted for by derecognition of the proportion of the asset disposed of, and recognition of
the consideration received or receivable from the farminee. A gain or loss is recognised for the difference between the net disposal
proceeds and the carrying value of the asset disposed. Consideration is initially recognised at fair value or the cash price equivalent where
payment is deferred. Interest revenue is recognised for the difference between the nominal amount of the consideration and the cash
price equivalent.
Any cash consideration received directly from a farminee in respect of the farmout of an exploration asset is credited against costs
previously capitalised, if applicable, with any excess accounted for as a gain on disposal.
56
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
57
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(a) Basis of Preparation (continued)
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 lease itself or, if not, whether it successfully recovers the related exploration and evaluation expenditure
through sale. Factors that impact recoverability may include, but are not limited to, the level of resources and reserves, the cost of
production, regulatory changes and commodity price movements. Ongoing exploration and evaluation expenditure is expensed as
incurred. Acquisition expenditure is capitalised if activities in the area of interest have not yet reached a stage that permits a reasonable
assessment of the existence or otherwise of economically recoverable reserves. To the extent that the capitalised acquisition expenditure
is determined not to be recoverable in future, profits and net assets will be reduced in the period in which this determination is made.
Further information on the carrying value of capitalised exploration and evaluation expenditure can be found in Note 13.
Other Non-financial Assets
Property, plant and equipment and other non-financial assets are written down immediately to their recoverable amount if the asset’s
carrying amount is greater than its estimated recoverable amount. Goodwill is tested for impairment annually or whenever events or
changes in circumstances indicate that the carrying amount may not be recoverable. For the purposes of assessing impairment, assets are
grouped at the lowest levels for which there are separately identifiable cash inflows which are largely independent of the cash inflows from
other assets or groups of assets (cash-generating units). Where discounted cash flows are used to assess recoverability of non-financial
assets, the Group is required to use assumptions in respect of future commodity prices, foreign exchange rates, interest rates and
operating costs, along with the possible impact of climate-related and other emerging business risks in determining expected future cash
flows from operations. Further information on the nature and carrying value of other non-financial assets can be found in Notes 11, 12, 14
and 16. Testing for impairment of goodwill and other non-financial assets in FY2022 was assessed against a recent market transaction
(refer Note 3(a)).
Taxation
future taxable profits.
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 Balance Sheet. Deferred tax assets, including those arising from un-recouped tax losses and capital losses,
are recognised only where it is considered more likely than not they will be recovered, which is dependent on the generation of sufficient
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 Balance Sheet and the amount of other tax losses and temporary
differences not yet recognised. In such circumstances, some or all of the carrying amounts of recognised deferred tax assets and liabilities
may require adjustment, resulting in a corresponding credit or charge to the Consolidated Statement of Profit or Loss and Other
Comprehensive Income.
(i)
Subsidiaries
(b) Principles of Consolidation
The consolidated financial statements incorporate the assets and liabilities of all subsidiaries of Central Petroleum Limited (“the Company”
or “Parent Entity”) as at 30 June and the results of all subsidiaries for the year then ended. Central Petroleum Limited and its subsidiaries
together are referred to in this financial report as “the Group” or “the Consolidated Entity”.
Subsidiaries are all entities (including structured entities) over which the Group has control. The Group controls an entity when the Group
is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its
power to direct the activities of the entity.
Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated from the date that
control ceases. The acquisition method is used to account for business combinations by the Group.
Intercompany transactions, balances and unrealised gains on transactions between Group entities are eliminated. Unrealised losses are
also eliminated unless the transaction provides evidence of the impairment of the asset transferred. Accounting policies of subsidiaries
have been changed where necessary to ensure consistency with the policies adopted by the Group.
Non-controlling interests (if applicable) in the results and equity of subsidiaries are shown separately in the statement of comprehensive
income, statement of changes in equity and balance sheet respectively.
56
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
(b) Principles of Consolidation (continued)
(ii)
Joint Arrangements
The Group’s investments in joint arrangements are classified as either joint operations or joint ventures; depending on the contractual
rights and obligations each investor has, rather than the legal structure of the joint arrangement.
The Group’s exploration and production activities are conducted through joint arrangements governed by joint operating agreements or
similar contractual relationships.
A joint operation involves the joint control, and often the joint ownership, of one or more assets contributed to, or acquired for the
purpose of, the joint operation and dedicated to the purposes of the joint operation. The assets are used to obtain benefits for the parties
to the joint operation. Each party may take a share of the output from the assets and each bears an agreed share of expenses incurred.
Each party has control over its share of future economic benefits through its share of the joint operation. The interests of the Group in joint
operations are brought to account by recognising in the financial statements the Group’s share of jointly controlled assets, share of
expenses and liabilities incurred, and the income from the sale or use of its share of the production of the joint operation in accordance
with the revenue policy in Note 1(e). Details of the joint operations are set out in Note 35.
(c) Segment Reporting
Operating segments are reported in Note 24 in a manner consistent with the internal reporting provided to the chief operating decision
makers. The chief operating decision makers, who are responsible for allocating resources and assessing performance of the operating
segments, have been identified as the Executive Management Team.
(d) Foreign Currency Translation
(i)
Functional and Presentation Currency
Items included in the financial statements of each of the Group’s entities are measured using the currency of the primary economic
environment in which the entity operates (the “functional currency”). The consolidated financial statements are presented in Australian
dollars, which is Central Petroleum Limited’s functional currency and presentation currency.
(ii)
Transactions and Balances
Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the
transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end
exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in profit or loss, except when they are
deferred in equity as qualifying cash flow hedges and qualifying net investment hedges or are attributable to part of the net investment in
a foreign operation.
(e) Revenue Recognition
Revenue from contracts with customers is recognised in the income statement when or as the Group transfers control of goods or services
to a customer at the amount to which the Group expects to be entitled. If the consideration promised includes a variable amount, the
Group estimates the amount of consideration to which it will be entitled.
(i)
Revenue from the sale of hydrocarbons
Revenue from the sale of hydrocarbons is recognised based on volumes sold under contracts with customers, at the point in time where
performance obligations are considered met. Generally, regarding the sale of hydrocarbon products, the performance obligation will be
met when the product is delivered to the specified measurement point (gas) or point of loading/unloading (liquids).
(ii)
Farmouts and terminations
Farmouts outside the exploration phase are accounted for by derecognition of the proportion of the asset disposed of, and recognition of
the consideration received or receivable from the farminee. A gain or loss is recognised for the difference between the net disposal
proceeds and the carrying value of the asset disposed. Consideration is initially recognised at fair value or the cash price equivalent where
payment is deferred. Interest revenue is recognised for the difference between the nominal amount of the consideration and the cash
price equivalent.
Any cash consideration received directly from a farminee in respect of the farmout of an exploration asset is credited against costs
previously capitalised, if applicable, with any excess accounted for as a gain on disposal.
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
57
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(e) Revenue Recognition (continued)
(iii) Contract Liabilities
A contract liability is recorded for obligations under sales contracts to deliver natural gas in future periods for which payment has already
been received (including “take-or-pay” arrangements). The Group applies the practical expedient in paragraph 121 of AASB 15 and does
not disclose information on the transaction price allocated to performance obligations that are unsatisfied.
(iv)
Interest Income
Interest income is recognised on a time proportionate basis that takes into account the effective yield on the financial assets.
(f) Government Grants
Cash grants from the government, including research and development concessions, are recognised at their fair value where there is a
reasonable assurance that the grant or refund will be received, and the Group has or will comply with any conditions attaching to the grant
or refund. Research and development grants are recognised as other income in the profit and loss where they relate to exploration
expenditure which has been expensed in the profit and loss. Grants in the form of wages subsidies are credited against employee costs.
Non-monetary grants are recognised at a nominal amount.
(g) Income Tax
Central Petroleum Limited and its wholly owned Australian controlled entities have implemented the tax consolidation legislation. The
head entity is Central Petroleum Limited. As a consequence, these entities are taxed as a single entity. The Company and the other entities
in the tax-consolidated group have entered into a tax funding and a tax sharing agreement.
The Group accounts for income taxes in accordance with UIG 1052 adopting the “Separate Taxpayer within Group Approach”.
The income tax expense or revenue for the period is the tax payable on the current period’s taxable income based on the applicable
income tax rate adjusted by changes in deferred tax assets and liabilities attributable to temporary differences. The current income tax
charge is calculated on the basis of the tax laws enacted or substantially enacted at the end of the reporting period in the countries where
entities in the Group generate taxable income.
Each individual entity recognises deferred tax assets and deferred tax liabilities arising from temporary differences on the basis that the
entity is subject to tax as part of the tax-consolidated group. Deferred tax assets are recognised for deductible temporary differences and
unused tax losses only if it is probable that future taxable amounts will be available to utilise those temporary differences and losses. Each
entity assesses the recovery of its unused tax losses and tax credits only in the period in which they arise and before assumption by the
head entity, applied in the context of the Group whether as a reduction of current tax of other entities in the group or as a deferred tax
asset of the head entity. The aggregate amount of losses or credits utilised or recognised as a deferred tax asset by the head entity is
apportioned on a systematic and reasonable basis.
Deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill. Deferred tax is also not accounted for if it
arises from initial recognition of an asset or liability in a transaction other than a business combination that, at the time of the transaction,
affects neither accounting nor taxable profit or loss. Deferred income tax is determined using tax rates (and laws) that have been enacted
or substantially enacted by the end of the reporting period and are expected to apply when the related deferred income tax asset is
realised, or the deferred income tax liability is settled.
Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets and liabilities and when the
deferred tax balances relate to the same taxation authority. Current tax assets and tax liabilities are offset where the entity has a legally
enforceable right to offset and intends either to settle on a net basis, or to realise the asset and settle the liability simultaneously.
(h) Leases
The Group’s accounting policy for leases where the Group is lessee is described in Note 12(c).
(i)
Impairment of Assets
Goodwill and intangible assets that have an indefinite useful life are not subject to amortisation and are tested annually for impairment, or
more frequently if events or changes in circumstances indicate that they might be impaired. Other assets are tested 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 inflows which are largely independent of the cash inflows from other assets or groups of assets (cash-
generating units). Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the impairment
at the end of each reporting period.
(j) Cash and Cash Equivalents
For the purpose of presentation in the statement of cash flows, cash and cash equivalents includes cash on hand, deposits held at call with
financial institutions, other short-term, highly liquid investments with original maturities of 3-months or less that are readily convertible to
known amounts of cash and which are subject to an insignificant risk of changes in value, and bank overdrafts. Bank overdrafts (if
applicable) are shown within borrowings in current liabilities in the balance sheet.
(k) Trade Receivables
Trade receivables are recognised initially at the amount of consideration that is unconditional unless they contain significant financing
components, when they are recognised at fair value. The Group holds the trade receivables with the objective to collect the contractual
cash flows and therefore measures them subsequently at amortised cost using the effective interest method.
The Group considers an allowance for expected credit losses (ECLs) for all receivables. The Group applies a simplified approach in
calculating ECLs which is based on an assessment on its historical credit loss experience, adjusted for factors specific to the debtors and the
economic environment. This includes, but is not limited to, financial difficulties of the debtor, probability that the debtor will enter
bankruptcy or financial reorganisation and delinquency in payments. Information about the impairment of trade receivables and the
Group’s exposure to credit risk, foreign currency risk and interest rate risk can be found in Note 33.
(l)
Inventories
Inventories comprise hydrocarbon stocks, drilling materials and spare parts and are valued at the lower of cost and net realisable value.
Costs are assigned to individual items of inventory on a first in first out or weighted average cost basis. Cost of inventory includes the
purchase price after deducting any rebates and discounts, as well as any associated freight charges.
Net realisable value is the estimated selling price in the ordinary course of business less the estimated costs necessary to make the sale.
(m) Other Financial Assets
(i)
Classification
classified as other financial assets (Note 15).
(ii) Measurement
The Group’s financial assets consist of receivables and security deposits. These are non-derivative financial assets with fixed or
determinable payments that are not quoted in an active market. They are included in current assets, except for those with maturities
greater than 12-months after the reporting period which are classified as non-current assets. Receivables are included in trade and other
receivables (Note 8) in the balance sheet. Amounts paid as performance bonds or amounts held as security for bank guarantees are
At initial recognition, the Group measures a financial asset at its fair value plus, in the case of a financial asset not at fair value through
profit or loss, transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets
carried at fair value through profit or loss are expensed in profit or loss. Financial assets carried at fair value through profit or loss are
revalued to fair value at the end of the reporting period. Loans and receivables are subsequently carried at amortised cost using the
effective interest method.
and the economic environment.
The Group considers an allowance for expected credit losses (ECLs) for its financial assets. The Group applies a simplified approach in
calculating ECLs which is based on an assessment on its historical credit loss experience, adjusted for factors specific to the counterparty
58
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
59
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(e) Revenue Recognition (continued)
(iii) Contract Liabilities
A contract liability is recorded for obligations under sales contracts to deliver natural gas in future periods for which payment has already
been received (including “take-or-pay” arrangements). The Group applies the practical expedient in paragraph 121 of AASB 15 and does
not disclose information on the transaction price allocated to performance obligations that are unsatisfied.
Interest income is recognised on a time proportionate basis that takes into account the effective yield on the financial assets.
(iv)
Interest Income
(f) Government Grants
Cash grants from the government, including research and development concessions, are recognised at their fair value where there is a
reasonable assurance that the grant or refund will be received, and the Group has or will comply with any conditions attaching to the grant
or refund. Research and development grants are recognised as other income in the profit and loss where they relate to exploration
expenditure which has been expensed in the profit and loss. Grants in the form of wages subsidies are credited against employee costs.
Non-monetary grants are recognised at a nominal amount.
(g) Income Tax
Central Petroleum Limited and its wholly owned Australian controlled entities have implemented the tax consolidation legislation. The
head entity is Central Petroleum Limited. As a consequence, these entities are taxed as a single entity. The Company and the other entities
in the tax-consolidated group have entered into a tax funding and a tax sharing agreement.
The Group accounts for income taxes in accordance with UIG 1052 adopting the “Separate Taxpayer within Group Approach”.
The income tax expense or revenue for the period is the tax payable on the current period’s taxable income based on the applicable
income tax rate adjusted by changes in deferred tax assets and liabilities attributable to temporary differences. The current income tax
charge is calculated on the basis of the tax laws enacted or substantially enacted at the end of the reporting period in the countries where
entities in the Group generate taxable income.
Each individual entity recognises deferred tax assets and deferred tax liabilities arising from temporary differences on the basis that the
entity is subject to tax as part of the tax-consolidated group. Deferred tax assets are recognised for deductible temporary differences and
unused tax losses only if it is probable that future taxable amounts will be available to utilise those temporary differences and losses. Each
entity assesses the recovery of its unused tax losses and tax credits only in the period in which they arise and before assumption by the
head entity, applied in the context of the Group whether as a reduction of current tax of other entities in the group or as a deferred tax
asset of the head entity. The aggregate amount of losses or credits utilised or recognised as a deferred tax asset by the head entity is
apportioned on a systematic and reasonable basis.
Deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill. Deferred tax is also not accounted for if it
arises from initial recognition of an asset or liability in a transaction other than a business combination that, at the time of the transaction,
affects neither accounting nor taxable profit or loss. Deferred income tax is determined using tax rates (and laws) that have been enacted
or substantially enacted by the end of the reporting period and are expected to apply when the related deferred income tax asset is
realised, or the deferred income tax liability is settled.
Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets and liabilities and when the
deferred tax balances relate to the same taxation authority. Current tax assets and tax liabilities are offset where the entity has a legally
enforceable right to offset and intends either to settle on a net basis, or to realise the asset and settle the liability simultaneously.
(h) Leases
The Group’s accounting policy for leases where the Group is lessee is described in Note 12(c).
(i)
Impairment of Assets
Goodwill and intangible assets that have an indefinite useful life are not subject to amortisation and are tested annually for impairment, or
more frequently if events or changes in circumstances indicate that they might be impaired. Other assets are tested 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 inflows which are largely independent of the cash inflows from other assets or groups of assets (cash-
generating units). Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the impairment
at the end of each reporting period.
(j) Cash and Cash Equivalents
For the purpose of presentation in the statement of cash flows, cash and cash equivalents includes cash on hand, deposits held at call with
financial institutions, other short-term, highly liquid investments with original maturities of 3-months or less that are readily convertible to
known amounts of cash and which are subject to an insignificant risk of changes in value, and bank overdrafts. Bank overdrafts (if
applicable) are shown within borrowings in current liabilities in the balance sheet.
(k) Trade Receivables
Trade receivables are recognised initially at the amount of consideration that is unconditional unless they contain significant financing
components, when they are recognised at fair value. The Group holds the trade receivables with the objective to collect the contractual
cash flows and therefore measures them subsequently at amortised cost using the effective interest method.
The Group considers an allowance for expected credit losses (ECLs) for all receivables. The Group applies a simplified approach in
calculating ECLs which is based on an assessment on its historical credit loss experience, adjusted for factors specific to the debtors and the
economic environment. This includes, but is not limited to, financial difficulties of the debtor, probability that the debtor will enter
bankruptcy or financial reorganisation and delinquency in payments. Information about the impairment of trade receivables and the
Group’s exposure to credit risk, foreign currency risk and interest rate risk can be found in Note 33.
(l)
Inventories
Inventories comprise hydrocarbon stocks, drilling materials and spare parts and are valued at the lower of cost and net realisable value.
Costs are assigned to individual items of inventory on a first in first out or weighted average cost basis. Cost of inventory includes the
purchase price after deducting any rebates and discounts, as well as any associated freight charges.
Net realisable value is the estimated selling price in the ordinary course of business less the estimated costs necessary to make the sale.
(m) Other Financial Assets
(i)
Classification
The Group’s financial assets consist of receivables and security deposits. These are non-derivative financial assets with fixed or
determinable payments that are not quoted in an active market. They are included in current assets, except for those with maturities
greater than 12-months after the reporting period which are classified as non-current assets. Receivables are included in trade and other
receivables (Note 8) in the balance sheet. Amounts paid as performance bonds or amounts held as security for bank guarantees are
classified as other financial assets (Note 15).
(ii) Measurement
At initial recognition, the Group measures a financial asset at its fair value plus, in the case of a financial asset not at fair value through
profit or loss, transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets
carried at fair value through profit or loss are expensed in profit or loss. Financial assets carried at fair value through profit or loss are
revalued to fair value at the end of the reporting period. Loans and receivables are subsequently carried at amortised cost using the
effective interest method.
The Group considers an allowance for expected credit losses (ECLs) for its financial assets. The Group applies a simplified approach in
calculating ECLs which is based on an assessment on its historical credit loss experience, adjusted for factors specific to the counterparty
and the economic environment.
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59
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(n) Property, Plant and Equipment – Development and Production Assets
(p) Exploration Expenditure
(i)
Assets in Development
The costs of oil and gas properties in the development phase are separately accounted for and include costs transferred from exploration
and evaluation assets once technical feasibility and commercial viability of an area of interest are demonstrable. When production
commences, the accumulated costs are transferred to producing areas of interest except for land and buildings and surface plant and
equipment associated with development assets which are recorded in the land and buildings and plant and equipment categories
respectively. Amortisation is not charged on costs carried forward in respect of areas of interest in the development phase until production
commences.
(ii)
Producing Assets
The costs of oil and gas properties in production are separately accounted for and include costs transferred from exploration and
evaluation assets, transferred development assets and the ongoing costs of continuing to develop reserves for production including an
estimate of the future costs to restore the site. Land and buildings and surface plant and equipment associated with producing areas of
interest are recorded in the land and buildings and plant and equipment categories respectively.
Depreciation of producing assets is calculated for an asset or group of assets from the date of commencement of production. Depletion
charges are calculated using the units of production method which will amortise the cost of carried forward exploration, evaluation,
subsurface development expenditure (subsurface assets) and capitalised restoration costs over the life of the estimated Proven plus
Probable (2P) hydrocarbon reserves for an asset or group of assets, together with estimated future costs necessary to develop the
hydrocarbon reserves included in the calculation.
(o) Property, Plant and Equipment – Other than Development and Production
Assets
All property, plant and equipment is stated at historical cost less depreciation. Historical cost includes expenditure that is directly
attributable to the acquisition of the items. Cost may also include transfers from equity of any gains or losses on qualifying cash flow
hedges of foreign currency purchases of property, plant and equipment.
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. The
carrying amount of any component accounted for as a separate asset is derecognised when replaced. All other repairs and maintenance
costs are charged to profit or loss during the reporting period in which they are incurred.
Land is not depreciated. Depreciation of plant and equipment is calculated on a reducing balance basis so as to write off the net costs of
each asset over the expected useful life. The assets' residual values and useful lives are reviewed, and adjusted if appropriate, at each
balance date.
An asset's carrying amount is written down immediately to its recoverable amount if the asset'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 profit or loss.
The expected useful life for each class of depreciable assets is:
Class of Fixed Asset
Expected Useful Life
Buildings
Leasehold Improvements
Plant and Equipment
Motor Vehicles
40 years
2 – 6 years
2 – 30 years
5 – 10 years
Exploration and evaluation costs are expensed as incurred. Acquisition costs of rights to explore are capitalised in respect of each separate
area of interest and carried forward where: right of tenure of the area of interest is current; these costs are expected to be recouped
through sale or successful development and exploitation of the area of interest; or where exploration and evaluation activities in the area
of interest have not yet reached a stage that permits reasonable assessment of the existence of economically recoverable reserves. No
amortisation is charged on acquisition costs capitalised under this policy.
When an area of interest is abandoned or the Directors decide that it is not commercial, any accumulated costs in respect of that area are
written off in the financial period the decision is made. Each area of interest is also reviewed at the end of each accounting period and
accumulated costs written off to the extent that they will not be recoverable in the future.
(q) Goodwill
Goodwill arising on the acquisition of subsidiaries is not amortised, but it is tested for impairment annually, or more frequently if events or
changes in circumstances indicate a potential impairment. Goodwill is carried at cost less accumulated impairment losses.
Goodwill is allocated to cash generating units for the purpose of impairment testing. The allocation is made to those cash-generating units
or groups of cash-generating units that are expected to benefit from the business combination in which the goodwill arose. The units or
groups of units are identified at the lowest level at which goodwill is monitored for internal management purposes, being the producing
assets segments (Note 24).
(r) Trade and Other Payables
These amounts represent liabilities for goods and services provided to the Group prior to the end of financial year which are unpaid. The
amounts are unsecured and are usually paid within 30 days of recognition, except contributions to Joint Arrangements that are settled in
line with the Joint Operating Agreements. Trade and other payables are presented as current liabilities unless payment is not due within
12-months from the reporting date. They are recognised initially at their fair value and subsequently measured at amortised cost using the
effective interest method.
(s) Provisions
of affected areas.
charge within finance costs.
Note 1(n)).
(ii) Onerous Contracts
(i)
Restoration and Rehabilitation
The Group records the present value of the estimated cost of legal and constructive obligations to restore operating locations in the period
in which the obligation arises. The nature of restoration activities includes the removal of facilities, abandonment of wells and restoration
A restoration provision is recognised and updated at different stages of the development and construction of a facility and then reviewed
on an annual basis. When the liability is initially recorded, the present value of the estimated future cost is capitalised by increasing the
carrying amount of the related property, plant and equipment. Over time, the liability is increased for the change in the present value
based on a pre-tax discount rate appropriate to the risks inherent in the liability. The unwinding of the discount is recorded as an accretion
The carrying amount capitalised in property, plant and equipment is depreciated over the useful life of the related producing asset (refer to
Costs incurred that relate to an existing condition caused by past operations and do not have a future economic benefit are expensed.
An Onerous Contracts provision is recognised where the unavoidable costs of meeting obligations under the contract exceeds the value of
the economic benefits expected to be received under the contract.
60 CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
61
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(n) Property, Plant and Equipment – Development and Production Assets
(p) Exploration Expenditure
(i)
Assets in Development
The costs of oil and gas properties in the development phase are separately accounted for and include costs transferred from exploration
and evaluation assets once technical feasibility and commercial viability of an area of interest are demonstrable. When production
commences, the accumulated costs are transferred to producing areas of interest except for land and buildings and surface plant and
equipment associated with development assets which are recorded in the land and buildings and plant and equipment categories
respectively. Amortisation is not charged on costs carried forward in respect of areas of interest in the development phase until production
commences.
(ii)
Producing Assets
The costs of oil and gas properties in production are separately accounted for and include costs transferred from exploration and
evaluation assets, transferred development assets and the ongoing costs of continuing to develop reserves for production including an
estimate of the future costs to restore the site. Land and buildings and surface plant and equipment associated with producing areas of
interest are recorded in the land and buildings and plant and equipment categories respectively.
Depreciation of producing assets is calculated for an asset or group of assets from the date of commencement of production. Depletion
charges are calculated using the units of production method which will amortise the cost of carried forward exploration, evaluation,
subsurface development expenditure (subsurface assets) and capitalised restoration costs over the life of the estimated Proven plus
Probable (2P) hydrocarbon reserves for an asset or group of assets, together with estimated future costs necessary to develop the
hydrocarbon reserves included in the calculation.
(o) Property, Plant and Equipment – Other than Development and Production
Assets
All property, plant and equipment is stated at historical cost less depreciation. Historical cost includes expenditure that is directly
attributable to the acquisition of the items. Cost may also include transfers from equity of any gains or losses on qualifying cash flow
hedges of foreign currency purchases of property, plant and equipment.
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. The
carrying amount of any component accounted for as a separate asset is derecognised when replaced. All other repairs and maintenance
costs are charged to profit or loss during the reporting period in which they are incurred.
Land is not depreciated. Depreciation of plant and equipment is calculated on a reducing balance basis so as to write off the net costs of
each asset over the expected useful life. The assets' residual values and useful lives are reviewed, and adjusted if appropriate, at each
balance date.
An asset's carrying amount is written down immediately to its recoverable amount if the asset'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 profit or loss.
The expected useful life for each class of depreciable assets is:
Class of Fixed Asset
Expected Useful Life
Buildings
Leasehold Improvements
Plant and Equipment
Motor Vehicles
40 years
2 – 6 years
2 – 30 years
5 – 10 years
Exploration and evaluation costs are expensed as incurred. Acquisition costs of rights to explore are capitalised in respect of each separate
area of interest and carried forward where: right of tenure of the area of interest is current; these costs are expected to be recouped
through sale or successful development and exploitation of the area of interest; or where exploration and evaluation activities in the area
of interest have not yet reached a stage that permits reasonable assessment of the existence of economically recoverable reserves. No
amortisation is charged on acquisition costs capitalised under this policy.
When an area of interest is abandoned or the Directors decide that it is not commercial, any accumulated costs in respect of that area are
written off in the financial period the decision is made. Each area of interest is also reviewed at the end of each accounting period and
accumulated costs written off to the extent that they will not be recoverable in the future.
(q) Goodwill
Goodwill arising on the acquisition of subsidiaries is not amortised, but it is tested for impairment annually, or more frequently if events or
changes in circumstances indicate a potential impairment. Goodwill is carried at cost less accumulated impairment losses.
Goodwill is allocated to cash generating units for the purpose of impairment testing. The allocation is made to those cash-generating units
or groups of cash-generating units that are expected to benefit from the business combination in which the goodwill arose. The units or
groups of units are identified at the lowest level at which goodwill is monitored for internal management purposes, being the producing
assets segments (Note 24).
(r) Trade and Other Payables
These amounts represent liabilities for goods and services provided to the Group prior to the end of financial year which are unpaid. The
amounts are unsecured and are usually paid within 30 days of recognition, except contributions to Joint Arrangements that are settled in
line with the Joint Operating Agreements. Trade and other payables are presented as current liabilities unless payment is not due within
12-months from the reporting date. They are recognised initially at their fair value and subsequently measured at amortised cost using the
effective interest method.
(s) Provisions
(i)
Restoration and Rehabilitation
The Group records the present value of the estimated cost of legal and constructive obligations to restore operating locations in the period
in which the obligation arises. The nature of restoration activities includes the removal of facilities, abandonment of wells and restoration
of affected areas.
A restoration provision is recognised and updated at different stages of the development and construction of a facility and then reviewed
on an annual basis. When the liability is initially recorded, the present value of the estimated future cost is capitalised by increasing the
carrying amount of the related property, plant and equipment. Over time, the liability is increased for the change in the present value
based on a pre-tax discount rate appropriate to the risks inherent in the liability. The unwinding of the discount is recorded as an accretion
charge within finance costs.
The carrying amount capitalised in property, plant and equipment is depreciated over the useful life of the related producing asset (refer to
Note 1(n)).
Costs incurred that relate to an existing condition caused by past operations and do not have a future economic benefit are expensed.
(ii) Onerous Contracts
An Onerous Contracts provision is recognised where the unavoidable costs of meeting obligations under the contract exceeds the value of
the economic benefits expected to be received under the contract.
60 CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
61
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(s) Provisions
(iii) Other
Provisions for legal claims and make good obligations are recognised when the Group has a present legal or constructive obligation as a
result of past events, it is probable that an outflow of resources will be required to settle the obligation and the amount has been reliably
estimated. 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.
Provisions are measured at the present value of management’s best estimate of the expenditure required to settle the present obligation
at the end of the reporting period. The discount rate used to determine the present value is a pre-tax rate that reflects current market
assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is
recognised as accretion expense within finance costs.
(t) Employee Benefits
(i)
Short-term Obligations
Liabilities for wages and salaries, including non-monetary benefits, annual leave and long service leave expected to be settled within
12-months after the end of the period in which the employees render the related service are recognised in respect of employees' services
up to the end of the reporting period and are measured at the amounts expected to be paid when the liabilities are settled. The liability for
annual leave and long service leave is recognised in the provision for employee benefits. All other short-term employee benefit obligations
are presented as payables.
(ii)
Long-term Employee Benefit Obligations
The liability for long service leave which is not expected to be settled within 12-months after the end of the period in which the employees
render the related service is recognised in the provision for employee benefits and measured as the present value of expected future
payments to be made in respect of services provided by employees up to the end of the reporting period. 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 end of the reporting period with terms to maturity and currency that match, as closely as possible,
the estimated future cash outflows.
(iii) Share-based Payments
Share-based compensation benefits are provided to employees by Central Petroleum Limited.
at cost in the financial statements of Central Petroleum Limited.
The fair value of options or rights granted is recognised as an employee benefits expense with a corresponding increase in equity. The total
amount to be expensed is determined by reference to the fair value of the rights or options granted, which includes any market
performance conditions and the impact of any non-vesting conditions but excludes the impact of any service and non-market performance
vesting conditions.
Non-market vesting conditions are included in assumptions about the number of rights or options that are expected to vest. The total
expense is recognised over the vesting period, which is the period over which all of the specified vesting conditions are to be satisfied. At
the end of each period, the entity revises its estimates of the number of rights or options that are expected to vest based on the non-
market vesting conditions. It recognises the impact of the revision to original estimates, if any, in profit or loss, with a corresponding
adjustment to equity.
(iv) Termination Benefits
Termination benefits are payable when employment is terminated by the Group before the normal retirement date, or when an employee
accepts voluntary redundancy in exchange for these benefits.
The Group recognises termination benefits at the earlier of the following dates: (a) when the Group can no longer withdraw the offer of
those benefits; and (b) when the entity recognises costs for a restructuring that is within the scope of AASB 137 and involves the payment
of terminations benefits. In the case of an offer made to encourage voluntary redundancy, the termination benefits are measured based on
the number of employees expected to accept the offer. Benefits falling due more than 12-months after the end of the reporting period are
discounted to present value.
62
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
63
Ordinary shares are classified as equity. Incremental costs directly attributable to the issue of new shares or options are shown in equity as
Provision is made for the amount of any dividend declared, being appropriately authorised and no longer at the discretion of the entity, on
or before the end of the reporting period but not distributed at the end of the reporting period.
(u) Contributed Equity
a deduction, net of tax, from the proceeds.
(v) Dividends
(w) Earnings Per Share
(i)
Basic Earnings Per Share
Basic earnings per share is calculated by dividing the profit attributable to owners of the Company, excluding any costs of servicing equity
other than ordinary shares, by the weighted average number of ordinary shares outstanding during the financial year.
(ii) Diluted Earnings Per Share
Diluted earnings per share adjusts the figures used in the determination of basic earnings per share to take into account the after income
tax effect of interest and other financing costs associated with dilutive potential ordinary shares and the weighted average number of
additional ordinary shares that would have been outstanding assuming the exercise of all dilutive potential ordinary shares.
(x) Goods and Services Tax (GST)
Revenues, expenses and assets are recognised net of the amount of GST, unless the GST incurred is not recoverable from the taxation
authority. In this case it is recognised as part of the cost of acquisition of the asset or as part of the expense. Receivables and payables are
stated inclusive of the amount of GST receivable or payable. The net amount of GST recoverable from, or payable to, the taxation authority
is included with other receivables or payables in the balance sheet.
Cash flows are presented on a gross basis. The GST components of cash flows arising from investing or financing activities which are
recoverable from, or payable to the taxation authority, are presented as operating cash flows.
(y) Parent Entity Financial Information
The financial information for the Parent Entity, Central Petroleum Limited, disclosed in Note 25, has been prepared on the same basis as
the consolidated financial statements except for investments in subsidiaries, associates and joint venture entities which are accounted for
(z) Business Combinations
The acquisition method of accounting is used to account for all business combinations, regardless of whether equity instruments or other
assets are acquired. The consideration transferred for the acquisition of a subsidiary comprises the:
fair values of the assets transferred;
liabilities incurred to the former owners of the acquired business;
equity interests issued by the Group;
fair value of any asset or liability resulting from a contingent consideration arrangement; and
fair value of any pre-existing equity interest in the subsidiary.
Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are, with limited exceptions,
measured initially at their fair values at the acquisition date. The Group recognises any non-controlling interest in the acquired entity on an
acquisition-by-acquisition basis either at fair value or at the non-controlling interest’s proportionate share of the acquired entity’s net
identifiable assets. Acquisition related costs are expensed as incurred.
The excess of the:
consideration transferred;
amount of any non-controlling interest in the acquired entity; and
acquisition-date fair value of any previous equity interest in the acquired entity
over the fair value of the net identifiable assets acquired is recorded as goodwill. If those amounts are less than the fair value of the net
identifiable assets of the business acquired, the difference is recognised directly in profit or loss as a bargain purchase.
•
•
•
•
•
•
•
•
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(u) Contributed Equity
Ordinary shares are classified as equity. Incremental costs directly attributable to the issue of new shares or options are shown in equity as
a deduction, net of tax, from the proceeds.
(v) Dividends
Provision is made for the amount of any dividend declared, being appropriately authorised and no longer at the discretion of the entity, on
or before the end of the reporting period but not distributed at the end of the reporting period.
(w) Earnings Per Share
(i)
Basic Earnings Per Share
Basic earnings per share is calculated by dividing the profit attributable to owners of the Company, excluding any costs of servicing equity
other than ordinary shares, by the weighted average number of ordinary shares outstanding during the financial year.
(ii) Diluted Earnings Per Share
Diluted earnings per share adjusts the figures used in the determination of basic earnings per share to take into account the after income
tax effect of interest and other financing costs associated with dilutive potential ordinary shares and the weighted average number of
additional ordinary shares that would have been outstanding assuming the exercise of all dilutive potential ordinary shares.
(x) Goods and Services Tax (GST)
Revenues, expenses and assets are recognised net of the amount of GST, unless the GST incurred is not recoverable from the taxation
authority. In this case it is recognised as part of the cost of acquisition of the asset or as part of the expense. Receivables and payables are
stated inclusive of the amount of GST receivable or payable. The net amount of GST recoverable from, or payable to, the taxation authority
is included with other receivables or payables in the balance sheet.
Cash flows are presented on a gross basis. The GST components of cash flows arising from investing or financing activities which are
recoverable from, or payable to the taxation authority, are presented as operating cash flows.
(y) Parent Entity Financial Information
The financial information for the Parent Entity, Central Petroleum Limited, disclosed in Note 25, has been prepared on the same basis as
the consolidated financial statements except for investments in subsidiaries, associates and joint venture entities which are accounted for
at cost in the financial statements of Central Petroleum Limited.
(z) Business Combinations
The acquisition method of accounting is used to account for all business combinations, regardless of whether equity instruments or other
assets are acquired. The consideration transferred for the acquisition of a subsidiary comprises the:
(s) Provisions
(iii) Other
Provisions for legal claims and make good obligations are recognised when the Group has a present legal or constructive obligation as a
result of past events, it is probable that an outflow of resources will be required to settle the obligation and the amount has been reliably
estimated. 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.
Provisions are measured at the present value of management’s best estimate of the expenditure required to settle the present obligation
at the end of the reporting period. The discount rate used to determine the present value is a pre-tax rate that reflects current market
assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is
recognised as accretion expense within finance costs.
(t) Employee Benefits
(i)
Short-term Obligations
Liabilities for wages and salaries, including non-monetary benefits, annual leave and long service leave expected to be settled within
12-months after the end of the period in which the employees render the related service are recognised in respect of employees' services
up to the end of the reporting period and are measured at the amounts expected to be paid when the liabilities are settled. The liability for
annual leave and long service leave is recognised in the provision for employee benefits. All other short-term employee benefit obligations
are presented as payables.
(ii)
Long-term Employee Benefit Obligations
The liability for long service leave which is not expected to be settled within 12-months after the end of the period in which the employees
render the related service is recognised in the provision for employee benefits and measured as the present value of expected future
payments to be made in respect of services provided by employees up to the end of the reporting period. 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 end of the reporting period with terms to maturity and currency that match, as closely as possible,
the estimated future cash outflows.
(iii) Share-based Payments
Share-based compensation benefits are provided to employees by Central Petroleum Limited.
The fair value of options or rights granted is recognised as an employee benefits expense with a corresponding increase in equity. The total
amount to be expensed is determined by reference to the fair value of the rights or options granted, which includes any market
performance conditions and the impact of any non-vesting conditions but excludes the impact of any service and non-market performance
vesting conditions.
Non-market vesting conditions are included in assumptions about the number of rights or options that are expected to vest. The total
expense is recognised over the vesting period, which is the period over which all of the specified vesting conditions are to be satisfied. At
the end of each period, the entity revises its estimates of the number of rights or options that are expected to vest based on the non-
market vesting conditions. It recognises the impact of the revision to original estimates, if any, in profit or loss, with a corresponding
adjustment to equity.
(iv) Termination Benefits
Termination benefits are payable when employment is terminated by the Group before the normal retirement date, or when an employee
accepts voluntary redundancy in exchange for these benefits.
The Group recognises termination benefits at the earlier of the following dates: (a) when the Group can no longer withdraw the offer of
those benefits; and (b) when the entity recognises costs for a restructuring that is within the scope of AASB 137 and involves the payment
of terminations benefits. In the case of an offer made to encourage voluntary redundancy, the termination benefits are measured based on
discounted to present value.
Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are, with limited exceptions,
measured initially at their fair values at the acquisition date. The Group recognises any non-controlling interest in the acquired entity on an
acquisition-by-acquisition basis either at fair value or at the non-controlling interest’s proportionate share of the acquired entity’s net
identifiable assets. Acquisition related costs are expensed as incurred.
fair values of the assets transferred;
liabilities incurred to the former owners of the acquired business;
equity interests issued by the Group;
fair value of any asset or liability resulting from a contingent consideration arrangement; and
fair value of any pre-existing equity interest in the subsidiary.
amount of any non-controlling interest in the acquired entity; and
acquisition-date fair value of any previous equity interest in the acquired entity
the number of employees expected to accept the offer. Benefits falling due more than 12-months after the end of the reporting period are
•
The excess of the:
consideration transferred;
•
•
•
•
•
•
over the fair value of the net identifiable assets acquired is recorded as goodwill. If those amounts are less than the fair value of the net
identifiable assets of the business acquired, the difference is recognised directly in profit or loss as a bargain purchase.
•
62
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
63
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
3. OTHER INCOME
(z) Business Combinations (continued)
Where settlement of any part of cash consideration is deferred, the amounts payable in the future are discounted to their present value as
at the date of exchange. The discount rate used is the entity’s incremental borrowing rate, being the rate at which a similar borrowing
could be obtained from an independent financier under comparable terms and conditions.
Interest
Income from financial assets at amortised cost
Profit on disposal of 50% of interests in Amadeus Basin producing properties (a)
Profit on disposal of inventory and other assets
Contingent consideration is classified either as equity or a financial liability. Amounts classified as a financial liability are subsequently
remeasured to fair value with changes in fair value recognised in profit or loss.
Total other income
If the business combination is achieved in stages, the acquisition date carrying value of the acquirer’s previously held equity interest in the
acquiree is remeasured to fair value at the acquisition date. Any gains or losses arising from such remeasurement are recognised in profit
or loss.
(aa) Standards, Amendments and Interpretations
The Group has applied the following standards and amendments for the first time for their annual reporting period commencing 1 July
2021:
AASB 2020-4 Amendments to Australian Accounting Standards – Covid-19-Related Rent Concessions [AASB 16], and
AASB 2020-8 Amendments to Australian Accounting Standards – Interest Rate Benchmark Reform – Phase 2 [AASB 4, AASB 7,
AASB 9, AASB 16 and AASB 139]
•
•
The amendments listed above did not have any impact on the amounts recognised in prior periods and are not expected to significantly
affect the current or future periods.
2. REVENUE FROM CONTRACTS WITH CUSTOMERS
(a) Revenue from contracts with customers
Sale of hydrocarbon products - point in time
Natural gas
Crude oil and condensate
Total revenue from contracts with customers
2022
$’000
36,255
5,896
42,151
2021
$’000
54,355
5,472
59,827
Revenue relating to contracts with major customers is disclosed in Note 24(f) – Segment Reporting.
(b) Contract Liabilities
Deferred Revenue – take-or-pay contracts1
Deferred Revenue – other gas sales contracts2
2022
Non-
current
$’000
Total
$’000
11,857
13,214
1,757
5,709
Current
$’000
1,357
3,952
Current
$’000
1,357
3,887
2021
Non-
current
$’000
Total
$’000
11,017
12,374
4,680
8,567
Total contract liabilities
5,309
13,614
18,923
5,244
15,697
20,941
1 Take-or-pay proceeds received are taken to revenue at the earlier of physical delivery of the gas to the customer, or upon forfeiture of the right to gas under the
contract. No revenue has been recognised during the year for gas forfeited under take-or-pay contracts.
2 Deferred Revenue from other contracts represents gas pre-sold to customers which is yet to be delivered. Amounts are recognised as Deferred Revenue when no
cash settlement option exists for the customer. Where a cash settlement option previously existed, the amount transferred to Deferred Revenue is the equivalent
fair value of that cash settlement option at the time that option ceased to be available.
Movements in contract liabilities during the year included a reduction of $5,186,000 (2021: $7,908,000) recognised as revenue from
amounts included in contract liabilities at the beginning of the year, partly offset by increases arising from finance charges, new take or pay
amounts received or accrued and adjustments to reflect the disposal of 50% of the Group’s interests in the Amadeus Basin producing
properties on 1 October 2021.
(a) Disposal of 50% interest in Amadeus Basin producing properties
On 25 May 2021, the Group announced it had entered into a binding agreement with New Zealand Oil and Gas Limited and Cue Energy
Resources Limited to sell 50% of the Group’s interests in its Amadeus Basin Producing Assets with an effective date of 1 July 2020. The
transaction completed on 1 October 2021 with the Group recording an accounting profit after tax of $36,559,000 comprised as follows:
Cash consideration received, net of adjustments from effective date to completion date and net of cash
included in disposal
Transaction costs
Net cash received
Fair Value of deferred consideration receivable post completion
Total consideration net of transaction costs
Carrying value of non-cash assets disposed
Carrying value of liabilities directly associated with assets disposed and included in the disposal
(a)
Profit before income tax includes the following specific expenses
Profit on disposal (after tax)
4. EXPENSES
Depreciation
Buildings
Producing assets
Plant and equipment
Leasehold improvements
Right of use assets
Total depreciation
Amortisation
Software
Rental expense relating to operating leases not recognised on the Balance
Sheet – Minimum lease payments
Finance costs
Interest and fees on debt facilities
Interest on lease liabilities
Amortisation of deferred finance costs
Accretion charges
Total finance costs
NOTE
11
11
11
11
12(b)
14
12(b)
12(b)
2022
$’000
63
665
36,559
13
37,300
2022
$’000
176
3,384
2,582
16
521
6,679
100
—
2,394
78
—
1,815
4,287
2021
$’000
76
—
—
79
155
$’000
29,561
(1,256)
28,305
29,849
58,154
(62,512)
40,917
36,559
2021
$’000
332
6,942
4,577
40
514
12,405
98
9
4,074
70
36
1,491
5,671
64
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
65
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
3. OTHER INCOME
(z) Business Combinations (continued)
Where settlement of any part of cash consideration is deferred, the amounts payable in the future are discounted to their present value as
at the date of exchange. The discount rate used is the entity’s incremental borrowing rate, being the rate at which a similar borrowing
could be obtained from an independent financier under comparable terms and conditions.
Interest
Income from financial assets at amortised cost
Profit on disposal of 50% of interests in Amadeus Basin producing properties (a)
Profit on disposal of inventory and other assets
Contingent consideration is classified either as equity or a financial liability. Amounts classified as a financial liability are subsequently
remeasured to fair value with changes in fair value recognised in profit or loss.
Total other income
2022
$’000
63
665
36,559
13
37,300
2021
$’000
76
—
—
79
155
If the business combination is achieved in stages, the acquisition date carrying value of the acquirer’s previously held equity interest in the
acquiree is remeasured to fair value at the acquisition date. Any gains or losses arising from such remeasurement are recognised in profit
or loss.
2021:
•
•
(aa) Standards, Amendments and Interpretations
The Group has applied the following standards and amendments for the first time for their annual reporting period commencing 1 July
AASB 2020-4 Amendments to Australian Accounting Standards – Covid-19-Related Rent Concessions [AASB 16], and
AASB 2020-8 Amendments to Australian Accounting Standards – Interest Rate Benchmark Reform – Phase 2 [AASB 4, AASB 7,
AASB 9, AASB 16 and AASB 139]
affect the current or future periods.
The amendments listed above did not have any impact on the amounts recognised in prior periods and are not expected to significantly
2. REVENUE FROM CONTRACTS WITH CUSTOMERS
(a) Revenue from contracts with customers
2022
$’000
36,255
5,896
42,151
2021
$’000
54,355
5,472
59,827
Sale of hydrocarbon products - point in time
Natural gas
Crude oil and condensate
Total revenue from contracts with customers
(b) Contract Liabilities
Deferred Revenue – take-or-pay contracts1
Deferred Revenue – other gas sales contracts2
Revenue relating to contracts with major customers is disclosed in Note 24(f) – Segment Reporting.
2022
Non-
current
$’000
Total
$’000
11,857
13,214
1,757
5,709
Current
$’000
1,357
3,952
Current
$’000
1,357
3,887
2021
Non-
current
$’000
Total
$’000
11,017
12,374
4,680
8,567
Total contract liabilities
5,309
13,614
18,923
5,244
15,697
20,941
1 Take-or-pay proceeds received are taken to revenue at the earlier of physical delivery of the gas to the customer, or upon forfeiture of the right to gas under the
contract. No revenue has been recognised during the year for gas forfeited under take-or-pay contracts.
2 Deferred Revenue from other contracts represents gas pre-sold to customers which is yet to be delivered. Amounts are recognised as Deferred Revenue when no
cash settlement option exists for the customer. Where a cash settlement option previously existed, the amount transferred to Deferred Revenue is the equivalent
fair value of that cash settlement option at the time that option ceased to be available.
Movements in contract liabilities during the year included a reduction of $5,186,000 (2021: $7,908,000) recognised as revenue from
amounts included in contract liabilities at the beginning of the year, partly offset by increases arising from finance charges, new take or pay
amounts received or accrued and adjustments to reflect the disposal of 50% of the Group’s interests in the Amadeus Basin producing
properties on 1 October 2021.
(a) Disposal of 50% interest in Amadeus Basin producing properties
On 25 May 2021, the Group announced it had entered into a binding agreement with New Zealand Oil and Gas Limited and Cue Energy
Resources Limited to sell 50% of the Group’s interests in its Amadeus Basin Producing Assets with an effective date of 1 July 2020. The
transaction completed on 1 October 2021 with the Group recording an accounting profit after tax of $36,559,000 comprised as follows:
Cash consideration received, net of adjustments from effective date to completion date and net of cash
included in disposal
Transaction costs
Net cash received
Fair Value of deferred consideration receivable post completion
Total consideration net of transaction costs
Carrying value of non-cash assets disposed
Carrying value of liabilities directly associated with assets disposed and included in the disposal
Profit on disposal (after tax)
4. EXPENSES
(a)
Profit before income tax includes the following specific expenses
Depreciation
Buildings
Producing assets
Plant and equipment
Leasehold improvements
Right of use assets
Total depreciation
Amortisation
Software
Rental expense relating to operating leases not recognised on the Balance
Sheet – Minimum lease payments
Finance costs
Interest and fees on debt facilities
Interest on lease liabilities
Amortisation of deferred finance costs
Accretion charges
Total finance costs
NOTE
11
11
11
11
12(b)
14
12(b)
12(b)
2022
$’000
176
3,384
2,582
16
521
6,679
100
—
2,394
78
—
1,815
4,287
$’000
29,561
(1,256)
28,305
29,849
58,154
(62,512)
40,917
36,559
2021
$’000
332
6,942
4,577
40
514
12,405
98
9
4,074
70
36
1,491
5,671
64
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
65
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
4. EXPENSES (CONTINUED)
(b) Government Grants
During the year $11,000 (2021: $218,000) was received from the Northern Territory Government as training incentives for operational staff
and recognised against net employee costs.
During the previous financial year, the Company recognised subsidies totalling $891,000 from the Australian Government against net
employee costs. These subsidies were in response to the impacts of COVID-19 and received under the JobKeeper support package
available to eligible affected businesses. No subsidies were received in the current financial year.
5.
INCOME TAX
This note provides an analysis of the Group’s income tax expense, shows what amounts are recognised directly in equity and how the tax
credit is affected by non-assessable and non-deductible items. It also explains significant estimates made in relation to the Group’s tax
position.
2022
$’000
2021
$’000
Net deferred tax assets not recognised
5.
INCOME TAX (CONTINUED)
(e) Deferred tax assets and liabilities
2022
$’000
2021
$’000
(a)
Income tax expense
Current tax
Deferred tax
Income tax expense
(b) Numerical reconciliation of income tax expense
and prima facie tax benefit
Profit before income tax expense
Prima facie tax expense at 30% (2021: 30%)
Tax effect of amounts which are not deductible in calculating taxable income:
Non-deductible expenses
Share based payments
Other items
Sub-total
Recognition of previously unrecognised deferred tax assets
Income tax expense
(c) Amounts recognised directly in equity
Aggregate deferred tax arising in the reporting period and not recognised in net
profit or loss or other comprehensive income but directly debited or credited to
equity:
Net deferred tax – debited directly to equity
Deferred tax assets not recognised
Net amounts recognised directly in equity
(d) Tax Losses
—
—
—
21,320
6,396
4
457
16
6,873
(6,873)
—
1
(1)
—
—
—
—
251
75
18
559
10
662
(662)
—
2
(2)
—
Unutilised tax losses for which no deferred tax asset has been recognised
Potential tax benefit at 30%
139.120
41,736
139,107
41,732
Unutilised tax losses are available for use in Australia and are available to offset future taxable profits of the income tax consolidated
group, subject to the relevant tax loss recoupment requirements being met.
Deferred tax assets
Provisions and accruals
Deferred revenue
Other expenditure
Borrowing costs
Unutilised losses
Total deferred tax assets before set-offs
Set-off of deferred tax liabilities pursuant to set-off provisions
Movements in deferred tax assets
Opening balance at 1 July
Charged to the income statement
Closing balance at 30 June
Deferred tax assets to be recovered after more than 12-months
Deferred tax assets to be recovered within 12-months
Deferred tax liabilities
Capitalised exploration
Property, plant and equipment
Total deferred tax liabilities before set-offs
Set-off of deferred tax assets pursuant to set-off provisions
Net deferred tax liabilities
Movements in deferred tax liabilities
Opening balance at 1 July
Credited to the income statement
Closing balance at 30 June1
Deferred tax liabilities to be recovered after more than 12-months
Deferred tax liabilities to be recovered within 12-months
1 At 30 June 2021 $4,781,000 of Deferred Tax Liabilities related to assets and liabilities classified as held for sale.
9,507
372
125
68
51,222
61,294
(9,487)
51,807
10,963
(1,476)
9,487
7,248
2,239
9,487
2,475
7,012
9,487
(9,487)
—
10,963
(1,476)
9,487
9,487
—
9,487
14,469
999
279
95
52,695
68,537
(10,963)
57,574
14,276
(3,313)
10,963
8,905
2,058
10,963
2,516
8,447
10,963
(10,963)
—
14,276
(3,313)
10,963
10,963
—
10,963
66
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
67
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
5.
INCOME TAX (CONTINUED)
(e) Deferred tax assets and liabilities
2022
$’000
2021
$’000
This note provides an analysis of the Group’s income tax expense, shows what amounts are recognised directly in equity and how the tax
credit is affected by non-assessable and non-deductible items. It also explains significant estimates made in relation to the Group’s tax
Total deferred tax assets before set-offs
Set-off of deferred tax liabilities pursuant to set-off provisions
2022
$’000
2021
$’000
Net deferred tax assets not recognised
Deferred tax assets
Provisions and accruals
Deferred revenue
Other expenditure
Borrowing costs
Unutilised losses
—
—
—
21,320
6,396
4
457
16
6,873
(6,873)
—
1
(1)
—
—
—
—
251
75
18
559
10
662
(662)
—
2
(2)
—
Movements in deferred tax assets
Opening balance at 1 July
Charged to the income statement
Closing balance at 30 June
Deferred tax assets to be recovered after more than 12-months
Deferred tax assets to be recovered within 12-months
Deferred tax liabilities
Capitalised exploration
Property, plant and equipment
Total deferred tax liabilities before set-offs
Set-off of deferred tax assets pursuant to set-off provisions
Net deferred tax liabilities
Movements in deferred tax liabilities
Opening balance at 1 July
Credited to the income statement
Closing balance at 30 June1
Deferred tax liabilities to be recovered after more than 12-months
Deferred tax liabilities to be recovered within 12-months
1 At 30 June 2021 $4,781,000 of Deferred Tax Liabilities related to assets and liabilities classified as held for sale.
9,507
372
125
68
51,222
61,294
(9,487)
51,807
10,963
(1,476)
9,487
7,248
2,239
9,487
2,475
7,012
9,487
(9,487)
—
10,963
(1,476)
9,487
9,487
—
9,487
14,469
999
279
95
52,695
68,537
(10,963)
57,574
14,276
(3,313)
10,963
8,905
2,058
10,963
2,516
8,447
10,963
(10,963)
—
14,276
(3,313)
10,963
10,963
—
10,963
4. EXPENSES (CONTINUED)
(b) Government Grants
and recognised against net employee costs.
During the year $11,000 (2021: $218,000) was received from the Northern Territory Government as training incentives for operational staff
During the previous financial year, the Company recognised subsidies totalling $891,000 from the Australian Government against net
employee costs. These subsidies were in response to the impacts of COVID-19 and received under the JobKeeper support package
available to eligible affected businesses. No subsidies were received in the current financial year.
5.
INCOME TAX
position.
(a)
Income tax expense
Current tax
Deferred tax
Income tax expense
(b) Numerical reconciliation of income tax expense
and prima facie tax benefit
Profit before income tax expense
Prima facie tax expense at 30% (2021: 30%)
Tax effect of amounts which are not deductible in calculating taxable income:
Non-deductible expenses
Share based payments
Other items
Sub-total
Income tax expense
Recognition of previously unrecognised deferred tax assets
(c) Amounts recognised directly in equity
Aggregate deferred tax arising in the reporting period and not recognised in net
profit or loss or other comprehensive income but directly debited or credited to
equity:
Net deferred tax – debited directly to equity
Deferred tax assets not recognised
Net amounts recognised directly in equity
(d) Tax Losses
Potential tax benefit at 30%
Unutilised tax losses for which no deferred tax asset has been recognised
Unutilised tax losses are available for use in Australia and are available to offset future taxable profits of the income tax consolidated
group, subject to the relevant tax loss recoupment requirements being met.
139.120
41,736
139,107
41,732
66
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
67
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
6. REMUNERATION OF AUDITORS
8.
TRADE AND OTHER RECEIVABLES (CONTINUED)
The following fees were paid or payable for services provided by PwC
Australia, the auditor of the Company, its related practices and non-related
audit firms:
(i)
(ii)
Audit and other assurance services
Audit and review of Group financial statements
Taxation services
Income Tax compliance
Other tax related services
Total taxation services
Total remuneration of PwC
7. CASH AND CASH EQUIVALENTS
Cash and cash equivalents
Made up as follows:
Corporate cash and bank balances (a)
Joint arrangements (b)
Cash and cash equivalents per Balance Sheet
Bank balances included in assets classified as held for sale (Note 10)
Total cash and cash equivalents
2022
$
2021
$
(b) Represents deferred consideration receivable in respect of the disposal of 50% of interests in the Amadeus Basin producing assets
(refer Note 3(a)). This is classified as a Financial Asset measured at amortised cost. During the year, $9,695,000 was recouped through
a free carry by the purchasers of Central’s share of expenditure on certain exploration and development projects. An amount of
$665,000 (2021: Nil) was recognised as Other Income as a result of adjustments to amortised cost for the period.
208,963
202,956
9.
INVENTORIES
9,588
10,579
20,167
9,129
26,864
35,993
229,130
238,949
2022
$000
21,647
20,577
1,070
21,647
—
21,647
2021
$000
37,165
36,281
878
37,159
6
37,165
10. ASSETS AND LIABILITIES CLASSIFIED AS HELD FOR SALE
At 30 June 2021, assets of $57,968,000 were classified as held for sale and liabilities of $39,436,000 were associated with the sale of 50% of
the Group’s interest in its producing assets in the Northern Territory. The transaction subsequently completed on 1 October 2021.
There were no assets classified as held for sale or associated liabilities at 30 June 2022.
At 30 June 2021, the major classes of assets comprising the sale interests classified as held for sale and associated liabilities were as
(a) $4,725,000 of this balance relates to cash held with Macquarie Bank Limited to be used for allowable purposes under the Facility
Property plant and equipment
Agreement (2021: $11,112,000), including, but not limited to operating costs for the Palm Valley, Dingo and Mereenie fields, taxes,
and debt servicing.
(b) This balance relates to the Group’s share of cash balances held under Joint Venture Arrangements.
(i)
Risk exposure
The Group’s exposure to credit and interest rate risk is discussed in Note 33.
8.
TRADE AND OTHER RECEIVABLES
Current
Trade debtors
Accrued income and recoveries (a)
Other receivables
Prepayments
Items measured at fair value through profit and loss:
Deferred receivable from partial sale of producing assets (b)
2022
$’000
639
3,533
578
1,302
20,820
26,872
2021
$’000
—
5,628
456
1,027
—
7,111
Liabilities directly associated with assets classified as held for sale
Total liabilities directly associated with assets classified as held for sale
(a) Accrued income and recoveries includes revenue recognised from hydrocarbon volumes delivered to respective customers but not yet
invoiced and accrued costs recoverable under Joint Arrangements.
Due to the nature of the Group’s receivables, their carrying values are considered to approximate their fair values. The Group applies the
simplified approach to providing for expected credit losses (refer Note 33(a)).
Crude oil and natural gas
Spare parts and consumables
Drilling materials and supplies at cost
Assets classified as held for sale
follows:
Cash
Receivables
Inventories
Right of use assets
Intangibles
Exploration assets
Goodwill
Total assets classified as held for sale
Trade and other payables
Current deferred revenue
Current lease liabilities
Non-current deferred revenue
Non-current lease liabilities
Non-current provisions
2022
$’000
45
1,228
2,595
3,868
2021
$’000
28
1,035
558
1,621
2021
$’000
6
175
1,053
54,294
145
17
325
1,953
57,968
2021
$’000
1,596
5,244
26
15,697
124
16,749
39,436
68
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 69
The following fees were paid or payable for services provided by PwC
Australia, the auditor of the Company, its related practices and non-related
audit firms:
(i)
Audit and other assurance services
Audit and review of Group financial statements
(ii)
Taxation services
Income Tax compliance
Other tax related services
Total taxation services
Total remuneration of PwC
7. CASH AND CASH EQUIVALENTS
Cash and cash equivalents
Made up as follows:
Corporate cash and bank balances (a)
Joint arrangements (b)
Cash and cash equivalents per Balance Sheet
Bank balances included in assets classified as held for sale (Note 10)
Total cash and cash equivalents
(i)
Risk exposure
The Group’s exposure to credit and interest rate risk is discussed in Note 33.
8.
TRADE AND OTHER RECEIVABLES
Accrued income and recoveries (a)
Current
Trade debtors
Other receivables
Prepayments
Items measured at fair value through profit and loss:
Deferred receivable from partial sale of producing assets (b)
(a) $4,725,000 of this balance relates to cash held with Macquarie Bank Limited to be used for allowable purposes under the Facility
Agreement (2021: $11,112,000), including, but not limited to operating costs for the Palm Valley, Dingo and Mereenie fields, taxes,
and debt servicing.
(b) This balance relates to the Group’s share of cash balances held under Joint Venture Arrangements.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
6. REMUNERATION OF AUDITORS
8.
TRADE AND OTHER RECEIVABLES (CONTINUED)
2022
$
2021
$
(b) Represents deferred consideration receivable in respect of the disposal of 50% of interests in the Amadeus Basin producing assets
(refer Note 3(a)). This is classified as a Financial Asset measured at amortised cost. During the year, $9,695,000 was recouped through
a free carry by the purchasers of Central’s share of expenditure on certain exploration and development projects. An amount of
$665,000 (2021: Nil) was recognised as Other Income as a result of adjustments to amortised cost for the period.
208,963
202,956
9.
INVENTORIES
229,130
238,949
Crude oil and natural gas
Spare parts and consumables
Drilling materials and supplies at cost
2022
$’000
45
1,228
2,595
3,868
2021
$’000
28
1,035
558
1,621
10. ASSETS AND LIABILITIES CLASSIFIED AS HELD FOR SALE
At 30 June 2021, assets of $57,968,000 were classified as held for sale and liabilities of $39,436,000 were associated with the sale of 50% of
the Group’s interest in its producing assets in the Northern Territory. The transaction subsequently completed on 1 October 2021.
There were no assets classified as held for sale or associated liabilities at 30 June 2022.
At 30 June 2021, the major classes of assets comprising the sale interests classified as held for sale and associated liabilities were as
follows:
Assets classified as held for sale
Cash
Receivables
Inventories
Property plant and equipment
Right of use assets
Intangibles
Exploration assets
Goodwill
Total assets classified as held for sale
Liabilities directly associated with assets classified as held for sale
Trade and other payables
Current deferred revenue
Current lease liabilities
Non-current deferred revenue
Non-current lease liabilities
Non-current provisions
Total liabilities directly associated with assets classified as held for sale
2021
$’000
6
175
1,053
54,294
145
17
325
1,953
57,968
2021
$’000
1,596
5,244
26
15,697
124
16,749
39,436
9,588
10,579
20,167
2022
$000
21,647
20,577
1,070
21,647
—
21,647
2022
$’000
639
3,533
578
1,302
20,820
26,872
9,129
26,864
35,993
2021
$000
37,165
36,281
878
37,159
6
37,165
2021
$’000
—
5,628
456
1,027
—
7,111
(a) Accrued income and recoveries includes revenue recognised from hydrocarbon volumes delivered to respective customers but not yet
invoiced and accrued costs recoverable under Joint Arrangements.
Due to the nature of the Group’s receivables, their carrying values are considered to approximate their fair values. The Group applies the
simplified approach to providing for expected credit losses (refer Note 33(a)).
68
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 69
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
11. PROPERTY, PLANT AND EQUIPMENT
12. LEASES (CONTINUED)
Year ended 30 June 2021
Opening net book amount
Additions
Changes to rehabilitation estimates
Disposals and write offs
Depreciation charge
Reclassified as held for sale
Closing net book amount
At 30 June 2021
Cost
Accumulated depreciation
Net book amount at 30 June 2021
Year ended 30 June 2022
Opening net book amount
Additions
Changes to rehabilitation estimates
Disposals and write offs
Depreciation charge
Closing net book amount
At 30 June 2022
Cost
Accumulated depreciation
Net book amount at 30 June 2022
Freehold Land
and Buildings
$’000
Producing
Assets
$’000
Plant and
Equipment
$’000
2,179
—
—
—
(332)
(917)
930
1,952
(1,022)
930
930
—
—
—
(176)
754
1,952
(1,198)
754
68,596
5,937
536
—
(6,942)
(34,254)
33,873
53,381
(19,508)
33,873
33,873
6,145
(278)
(2,984)
(3,384)
33,372
56,264
(22,892)
33,372
37,070
5,855
4
(4)
(4,617)
(19,123)
19,185
40,211
(21,026)
19,185
19,185
3,908
3
(778)
(2,598)
19,720
43,327
(23,607)
19,720
At 30 June 2022, $2,011,000 of property plant and equipment balances relates to assets under construction and is not subject to
depreciation until complete (2021: $3,015,000).
12. LEASES
(a) Amounts recognised in the balance sheet
The balance sheet shows the following amounts relating to leases:
Right-of-use assets
Land & Buildings
Plant & Equipment
Lease Liabilities
Current
Non-current
2022
$’000
832
90
922
413
588
1,001
Total
$’000
107,845
11,792
540
(4)
(11,891)
(54,294)
53,988
95,544
(41,556)
53,988
53,988
10,053
(275)
(3,762)
(6,158)
53,846
101,543
(47,697)
53,846
2021
$’000
1,211
244
1,455
517
992
1,509
Additions to the right-of-use assets during the 2022 financial year were $24,000 (2021: $1,055,000). Disposals and incentive adjustments
amounted to $36,000 (2021: Nil).
(b) Amounts recognised in the statement of profit or loss
The statement of profit or loss shows the following amounts relating to leases:
Depreciation charge of right-of-use assets
Land & Buildings
Plant & Equipment
Total depreciation of right-of-use assets
Interest expense
administrative expenses
Expense related to short term leases included in cost of sales and general and
The total cash outflow for leases in 2022 was $638,000 (2021: $691,000).
2022
$’000
2021
$’000
367
154
521
78
—
359
155
514
70
9
(c)
The Group’s leasing activities and how they are accounted for
The Group leases office space, property easements, equipment and vehicles. Rental contracts are typically made for fixed periods of 3 to 8
years but may have extension options as described below. Lease terms are negotiated on an individual basis and contain a wide range of
different terms and conditions. The lease agreements do not impose any covenants other than the security interests in the leased assets
that are held by the lessor. Leased assets may not be used as security for borrowing purposes.
Contracts may contain both lease and non-lease components. The Group has elected not to separate lease and non-lease components and
instead accounts for these as a single lease component.
Leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use by the
Group. Each lease payment is allocated between the liability and finance cost. The finance cost is charged to profit or loss over the lease
period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period.
Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of the
following lease payments:
fixed payments (including in-substance fixed payments), less any lease incentives receivable;
variable lease payment that are based on an index or a rate;
amounts expected to be payable by the lessee under residual value guarantees;
the exercise price of a purchase option if the lessee is reasonably certain to exercise that option; and
payments of penalties for terminating the lease, if the lease term reflects the lessee exercising that option.
Extension and termination options are included in some leases across the Group. These are used to maximise operational flexibility in
terms of managing the assets used in the Group’s operations. The extension and termination options held are exercisable only by the
Group and not by the respective lessor. Lease payments to be made under reasonably certain extension options are also included in the
measurement of the liability.
The lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be determined, the lessee’s incremental
borrowing rate is used, being the rate that the lessee would have to pay to borrow the funds necessary to obtain an asset of similar value
in a similar economic environment with similar terms, security and conditions.
To determine the incremental borrowing rate, the Group:
where possible, uses recent third-party financing received by the individual lessee as a starting point, adjusted to reflect changes
in financing conditions since third party financing was received;
uses a build-up approach that starts with a risk-free interest rate adjusted for credit risk for leases held by Central Petroleum
Limited, which does not have recent third-party financing; and
makes adjustments specific to the lease, e.g. term, country, currency and security.
The Group is exposed to potential future increases in variable lease payments based on an index or rate, which are not included in the
lease liability until they take effect. When adjustments to lease payments based on an index or rate take effect, the lease liability is
reassessed and adjusted against the right-of-use asset.
•
•
•
•
•
•
•
•
70
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
71
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
11. PROPERTY, PLANT AND EQUIPMENT
12. LEASES (CONTINUED)
Freehold Land
and Buildings
$’000
Producing
Assets
$’000
Plant and
Equipment
$’000
(b) Amounts recognised in the statement of profit or loss
The statement of profit or loss shows the following amounts relating to leases:
Depreciation charge of right-of-use assets
Land & Buildings
Plant & Equipment
Total depreciation of right-of-use assets
Interest expense
Expense related to short term leases included in cost of sales and general and
administrative expenses
The total cash outflow for leases in 2022 was $638,000 (2021: $691,000).
2022
$’000
2021
$’000
367
154
521
78
—
359
155
514
70
9
(c)
The Group’s leasing activities and how they are accounted for
The Group leases office space, property easements, equipment and vehicles. Rental contracts are typically made for fixed periods of 3 to 8
years but may have extension options as described below. Lease terms are negotiated on an individual basis and contain a wide range of
different terms and conditions. The lease agreements do not impose any covenants other than the security interests in the leased assets
that are held by the lessor. Leased assets may not be used as security for borrowing purposes.
Contracts may contain both lease and non-lease components. The Group has elected not to separate lease and non-lease components and
instead accounts for these as a single lease component.
Leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use by the
Group. Each lease payment is allocated between the liability and finance cost. The finance cost is charged to profit or loss over the lease
period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period.
Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of the
following lease payments:
•
•
•
•
•
fixed payments (including in-substance fixed payments), less any lease incentives receivable;
variable lease payment that are based on an index or a rate;
amounts expected to be payable by the lessee under residual value guarantees;
the exercise price of a purchase option if the lessee is reasonably certain to exercise that option; and
payments of penalties for terminating the lease, if the lease term reflects the lessee exercising that option.
Extension and termination options are included in some leases across the Group. These are used to maximise operational flexibility in
terms of managing the assets used in the Group’s operations. The extension and termination options held are exercisable only by the
Group and not by the respective lessor. Lease payments to be made under reasonably certain extension options are also included in the
measurement of the liability.
The lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be determined, the lessee’s incremental
borrowing rate is used, being the rate that the lessee would have to pay to borrow the funds necessary to obtain an asset of similar value
in a similar economic environment with similar terms, security and conditions.
To determine the incremental borrowing rate, the Group:
•
•
•
where possible, uses recent third-party financing received by the individual lessee as a starting point, adjusted to reflect changes
in financing conditions since third party financing was received;
uses a build-up approach that starts with a risk-free interest rate adjusted for credit risk for leases held by Central Petroleum
Limited, which does not have recent third-party financing; and
makes adjustments specific to the lease, e.g. term, country, currency and security.
The Group is exposed to potential future increases in variable lease payments based on an index or rate, which are not included in the
lease liability until they take effect. When adjustments to lease payments based on an index or rate take effect, the lease liability is
reassessed and adjusted against the right-of-use asset.
Year ended 30 June 2021
Opening net book amount
Additions
Changes to rehabilitation estimates
Disposals and write offs
Depreciation charge
Reclassified as held for sale
Closing net book amount
At 30 June 2021
Cost
Accumulated depreciation
Net book amount at 30 June 2021
Year ended 30 June 2022
Opening net book amount
Additions
Changes to rehabilitation estimates
Disposals and write offs
Depreciation charge
Closing net book amount
At 30 June 2022
Cost
Accumulated depreciation
Net book amount at 30 June 2022
Right-of-use assets
Land & Buildings
Plant & Equipment
Lease Liabilities
Current
Non-current
2,179
—
—
—
(332)
(917)
930
1,952
(1,022)
930
930
—
—
—
(176)
754
1,952
(1,198)
754
68,596
5,937
536
—
(6,942)
(34,254)
33,873
53,381
(19,508)
33,873
33,873
6,145
(278)
(2,984)
(3,384)
33,372
56,264
(22,892)
33,372
Total
$’000
107,845
11,792
540
(4)
(11,891)
(54,294)
53,988
95,544
(41,556)
53,988
53,988
10,053
(275)
(3,762)
(6,158)
53,846
101,543
(47,697)
53,846
2021
$’000
1,211
244
1,455
517
992
1,509
37,070
5,855
4
(4)
(4,617)
(19,123)
19,185
40,211
(21,026)
19,185
19,185
3,908
3
(778)
(2,598)
19,720
43,327
(23,607)
19,720
2022
$’000
832
90
922
413
588
1,001
At 30 June 2022, $2,011,000 of property plant and equipment balances relates to assets under construction and is not subject to
depreciation until complete (2021: $3,015,000).
12. LEASES
(a) Amounts recognised in the balance sheet
The balance sheet shows the following amounts relating to leases:
Additions to the right-of-use assets during the 2022 financial year were $24,000 (2021: $1,055,000). Disposals and incentive adjustments
amounted to $36,000 (2021: Nil).
70
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
71
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
12. LEASES (CONTINUED)
(c)
The Group’s leasing activities and how they are accounted for (continued)
Right-of-use assets are measured at cost comprising the following:
•
•
•
•
the amount of the initial measurement of lease liability;
any lease payments made at or before the commencement date less any lease incentives received;
any initial direct costs; and
the present value of estimated future restoration costs.
Right-of-use assets are generally depreciated over the shorter of the asset's useful life and the lease term on a straight-line basis. If the
Group is reasonably certain to exercise a purchase option, the right-of-use asset is depreciated over the underlying asset’s useful life.
16. GOODWILL
Payments associated with short-term leases and leases of low-value assets are recognised on a straight-line basis as an expense in profit or
loss. Short-term leases are leases with a lease term of 12-months or less.
If there is a modification to a lease arrangement, a determination of whether the modification results in a separate lease arrangement
being recognised needs to be made. Where the modification does result in a separate lease arrangement needing to be recognised, due to
an increase in scope of a lease through additional underlying leased assets and a commensurate increase in lease payments, the
measurement requirements as described above need to be applied.
Where the modification does not result in a separate lease arrangement, from the effective date of the modification, the Group will
remeasure the lease liability using the redetermined lease term, lease payments and applicable discount rate. A corresponding adjustment
will be made to the carrying amount of the associated right-of-use asset. Additionally, where there has been a partial or full termination of
a lease, the Group will recognise any resulting gain or loss in the income statement.
13. EXPLORATION ASSETS
Acquisition costs of right to explore
Movement for the year:
Balance at the beginning of the year
Reclassified as held for sale (Note 10)
Balance at the end of the year
14.
INTANGIBLE ASSETS
Software
At the beginning of the year
Cost
Accumulated amortisation
Net book value
Movements for the year
Opening net book amount
Additions
Amortisation
Reclassified as held for sale
Closing net book amount
At the end of the year
Cost
Accumulated amortisation
Net book value
2022
$’000
8,397
8,397
—
8,397
2022
$’000
848
(546)
302
302
177
(100)
—
379
1,025
(646)
379
2021
$’000
8,397
8,722
(325)
8,397
2021
$’000
788
(476)
312
312
105
(98)
(17)
302
848
(546)
302
15. OTHER FINANCIAL ASSETS
Non-Current
Security bonds on exploration permits and rental properties
Security bonds are provided to State or Territory governments in respect of certain performance obligations arising from awarded
petroleum and mineral tenements. The bonds are typically provided as cash or as bank guarantees in favour of the State or Territory
government secured by term deposits with the financial institution providing the bank guarantee.
2022
$’000
4,410
2021
$’000
4,218
2022
$’000
1,953
2021
$’000
1,953
Goodwill arising from business combinations
Movement
Impairment tests for goodwill
As at 30 June 2021, an additional $1,953,000 of goodwill was included in assets held for sale reflecting the 50% disposal interests (refer
Note 10). The sale subsequently completed on 1 October 2021 (refer Note 3(a)).
Goodwill is monitored by management at the level of the operating segments and has been allocated to the gas producing assets cash
generating unit. There has been no impairment of amounts previously recognised as goodwill. Goodwill is tested for impairment where an
indicator of impairment exists, and at least on an annual basis.
On 25 May 2021 the Group entered into a binding agreement with New Zealand Oil & Gas Limited (NZOG) and Cue Energy Resources
Limited (Cue) to sell 50% of the Group’s equity interests in its Amadeus Basin producing assets. The transaction completed on 1 October
2021 with the Group recording a book profit on sale of $36.6 million (refer Note 3(a)). The assets disposed represented 50% of the total
cash generating unit upon which Central assesses recoverable amount each year.
Management and the Board have concluded that this transaction provides evidence of the fair value of the underlying assets, net of
liabilities, being disposed and will therefore adopt the fair value less costs of disposal measurement methodology as at 30 June 2022.
Fair Value Measurement is governed by AASB 13 which defines fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at the measurement date. It assumes the asset or liability is
exchanged in an orderly transaction between market participants at the measurement date under current market conditions.
Management and the Board believe the sale process meets the requirements of an orderly transaction where all parties were acting in
their own economic best interests and therefore can be relied upon as evidence of the fair value of the assets being disposed net of the
liabilities being transferred. In addition, since the sale completed, the Group announced an increase in 2P reserves at 31 December 2021
and commenced selling gas into the East Coast gas spot market at higher realised prices.
The value of the transaction consideration (grossed up for the value of liabilities assumed by the purchaser) substantially exceeds the net
carrying value of the remaining 50% interests in the Amadeus Basin producing assets and associated goodwill. On this basis Management
and the Board have concluded there is no impairment of the carrying value of Goodwill or other producing assets at 30 June 2022.
17. TRADE AND OTHER PAYABLES
Current
Trade payables
Other payables
Accruals
2022
$’000
7,817
4
5,705
13,526
2021
$’000
5,312
31
5,148
10,491
Trade payables are usually non-interest bearing, provided payment is made within the terms of credit. The Consolidated Entity’s exposure
to liquidity and currency risks related to trade and other payables is disclosed in Note 33.
72
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
73
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
12. LEASES (CONTINUED)
(c)
The Group’s leasing activities and how they are accounted for (continued)
Right-of-use assets are measured at cost comprising the following:
the amount of the initial measurement of lease liability;
any lease payments made at or before the commencement date less any lease incentives received;
any initial direct costs; and
the present value of estimated future restoration costs.
•
•
•
•
15. OTHER FINANCIAL ASSETS
Non-Current
Security bonds on exploration permits and rental properties
2022
$’000
4,410
2021
$’000
4,218
Security bonds are provided to State or Territory governments in respect of certain performance obligations arising from awarded
petroleum and mineral tenements. The bonds are typically provided as cash or as bank guarantees in favour of the State or Territory
government secured by term deposits with the financial institution providing the bank guarantee.
Right-of-use assets are generally depreciated over the shorter of the asset's useful life and the lease term on a straight-line basis. If the
Group is reasonably certain to exercise a purchase option, the right-of-use asset is depreciated over the underlying asset’s useful life.
16. GOODWILL
Goodwill arising from business combinations
Movement
2022
$’000
1,953
2021
$’000
1,953
As at 30 June 2021, an additional $1,953,000 of goodwill was included in assets held for sale reflecting the 50% disposal interests (refer
Note 10). The sale subsequently completed on 1 October 2021 (refer Note 3(a)).
Impairment tests for goodwill
Goodwill is monitored by management at the level of the operating segments and has been allocated to the gas producing assets cash
generating unit. There has been no impairment of amounts previously recognised as goodwill. Goodwill is tested for impairment where an
indicator of impairment exists, and at least on an annual basis.
On 25 May 2021 the Group entered into a binding agreement with New Zealand Oil & Gas Limited (NZOG) and Cue Energy Resources
Limited (Cue) to sell 50% of the Group’s equity interests in its Amadeus Basin producing assets. The transaction completed on 1 October
2021 with the Group recording a book profit on sale of $36.6 million (refer Note 3(a)). The assets disposed represented 50% of the total
cash generating unit upon which Central assesses recoverable amount each year.
Management and the Board have concluded that this transaction provides evidence of the fair value of the underlying assets, net of
liabilities, being disposed and will therefore adopt the fair value less costs of disposal measurement methodology as at 30 June 2022.
Fair Value Measurement is governed by AASB 13 which defines fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at the measurement date. It assumes the asset or liability is
exchanged in an orderly transaction between market participants at the measurement date under current market conditions.
Management and the Board believe the sale process meets the requirements of an orderly transaction where all parties were acting in
their own economic best interests and therefore can be relied upon as evidence of the fair value of the assets being disposed net of the
liabilities being transferred. In addition, since the sale completed, the Group announced an increase in 2P reserves at 31 December 2021
and commenced selling gas into the East Coast gas spot market at higher realised prices.
The value of the transaction consideration (grossed up for the value of liabilities assumed by the purchaser) substantially exceeds the net
carrying value of the remaining 50% interests in the Amadeus Basin producing assets and associated goodwill. On this basis Management
and the Board have concluded there is no impairment of the carrying value of Goodwill or other producing assets at 30 June 2022.
17. TRADE AND OTHER PAYABLES
Current
Trade payables
Other payables
Accruals
2022
$’000
7,817
4
5,705
13,526
2021
$’000
5,312
31
5,148
10,491
Trade payables are usually non-interest bearing, provided payment is made within the terms of credit. The Consolidated Entity’s exposure
to liquidity and currency risks related to trade and other payables is disclosed in Note 33.
Payments associated with short-term leases and leases of low-value assets are recognised on a straight-line basis as an expense in profit or
loss. Short-term leases are leases with a lease term of 12-months or less.
If there is a modification to a lease arrangement, a determination of whether the modification results in a separate lease arrangement
being recognised needs to be made. Where the modification does result in a separate lease arrangement needing to be recognised, due to
an increase in scope of a lease through additional underlying leased assets and a commensurate increase in lease payments, the
measurement requirements as described above need to be applied.
Where the modification does not result in a separate lease arrangement, from the effective date of the modification, the Group will
remeasure the lease liability using the redetermined lease term, lease payments and applicable discount rate. A corresponding adjustment
will be made to the carrying amount of the associated right-of-use asset. Additionally, where there has been a partial or full termination of
a lease, the Group will recognise any resulting gain or loss in the income statement.
13. EXPLORATION ASSETS
Acquisition costs of right to explore
Movement for the year:
Balance at the beginning of the year
Reclassified as held for sale (Note 10)
Balance at the end of the year
14.
INTANGIBLE ASSETS
At the beginning of the year
Software
Cost
Accumulated amortisation
Net book value
Movements for the year
Opening net book amount
Additions
Amortisation
Reclassified as held for sale
Closing net book amount
At the end of the year
Cost
Accumulated amortisation
Net book value
2022
$’000
8,397
8,397
—
8,397
2022
$’000
848
(546)
302
302
177
(100)
—
379
1,025
(646)
379
2021
$’000
8,397
8,722
(325)
8,397
2021
$’000
788
(476)
312
312
105
(98)
(17)
302
848
(546)
302
72
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
73
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
2022
$’000
4,500
2021
$’000
36,000
26,309
30,809
Total
$’000
4,921
23,632
2,952
2021
Current Non-Current
$’000
$’000
1,084
23,466
2,829
3,184
—
734
3,918
Total
$’000
4,268
23,466
3,563
25,180
31,505
27,379
31,297
18. BORROWINGS
(a)
Current1
Debt facilities
(b)
Non-current1
Debt facilities
1 Details regarding interest bearing liabilities are contained in Note 33(e).
19. PROVISIONS
2022
Current Non-Current
$’000
$’000
Employee entitlements (a)
Restoration and rehabilitation (b)
Joint Venture production over-lift (c)
4,043
1,512
770
6,325
878
22,120
2,182
20. CONTRIBUTED EQUITY
(a)
Share capital
2022
$’000
2021
$’000
725,907,449 fully paid ordinary shares (2021: 724,093,661)
197,776
197,776
Ordinary shares have no par value, and the Company does not have a limited amount of authorised capital.
On a show of hands, every holder of ordinary shares present at a meeting in person or by proxy, is entitled to one vote, and upon a poll
each share is entitled to one vote.
Movements in ordinary share capital
2022
2021
Number of Shares
Number of Shares
Balance at start of year
Shares issued under Employee Incentive Plans
724,093,661
1,813,788
723,288,869
804,792
Balance at end of year
725,907,449
724,093,661
(b)
Share Options
The following table shows the movement in options over ordinary shares during the year:
2022
$’000
197,776
—
197,776
2021
$’000
197,776
—
197,776
Expiry Date
Price
Start of Year
During the Year
During the Year
Year
Year
Exercise
Balance at
Issued
Cancelled
During the
End of the
Exercised
Balance at the
Executive Share Option Plan
30 Jun 2023
$0.200
18,151,116
18,151,116
—
—
(930,070)
(930,070)
—
—
17,221,046
17,221,046
Class
Total
(c)
Share rights
Under the Group’s Employee Rights Plan, eligible employees may receive rights to shares in Central Petroleum Limited. The rights are
granted in respect of a plan year which commences 1 July each year. The share rights remain unvested until the end of the performance
period, which is three years commencing from the start of each plan year. Except in a limited number of circumstances, eligible employees
must still be in the employment of Central Petroleum Limited as at the vesting date for the rights to vest.
The number of rights to be granted to eligible employees is determined based on the maximum long term incentive amount applicable for
each eligible employee, being either a fixed dollar amount (which are not subject to performance hurdles) or a percentage of the
employee’s base salary, divided by the volume weighted average share price at the start of the plan year.
For those determined by performance hurdles, final vesting percentages reference a combination of absolute total shareholder return and
relative total shareholder return compared to a specific group of exploration and production companies.
Rights issued to non-executive directors during FY2022 were issued under a fee sacrifice arrangement. The number of rights issued was
based on the value of fees sacrificed at a volume weighted average price for the 20 days immediately following the date on which the
Company’s 2021 full year results were released.
(a) The current provision for employee entitlements includes accrued short term incentive plans, severance entitlements, accrued annual
leave and the unconditional entitlements to long service leave where employees have completed the required period of service. The
amounts are presented as current, since the Consolidated Entity does not have an unconditional right to defer settlement for these
obligations. However, based on past experience, the Group does not expect all employees to take the full amount of accrued leave or
require payment in the next 12-months. Current leave obligations that are not expected to be taken or paid within the next
12-months amount to $732,000 (2021: $635,000).
(b) Provisions for future removal and restoration costs are recognised where there is a present obligation and it is probable that an
outflow of economic benefits will be required to settle the obligation. The estimated future obligations include the costs of removing
facilities, abandoning wells and restoring the affected areas.
(c) Under an Interim Gas Balancing Agreement with its joint venture partners, the Group has taken a higher proportion of natural gas
produced from the Mereenie joint venture than its joint venture percentage entitlement. A provision has been recognised to reflect
the expected additional production costs of rebalancing production entitlements between the joint venture partners from future
operations.
Movements in Provisions
Movements in each class of provision during the financial year are set out below:
Employee
Entitlements
$’000
Restoration &
Rehabilitation
$’000
Joint Venture
Production
Over-Lift
$’000
2022
Carrying amount at start of year
Change in provision charged/(credited) to property,
plant and equipment
Additional provisions charged to profit or loss
Unwinding of discount
Amounts used during the year
Carrying amount at end of year
4,268
—
2,652
—
(1,999)
4,921
23,466
3,563
(275)
65
376
—
—
118
—
(729)
23,632
2,952
31,505
Total
$’000
31,297
(275)
2,835
376
(2,728)
74
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
75
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
20. CONTRIBUTED EQUITY
(a)
Share capital
2022
$’000
2021
$’000
725,907,449 fully paid ordinary shares (2021: 724,093,661)
197,776
197,776
Ordinary shares have no par value, and the Company does not have a limited amount of authorised capital.
On a show of hands, every holder of ordinary shares present at a meeting in person or by proxy, is entitled to one vote, and upon a poll
each share is entitled to one vote.
Movements in ordinary share capital
2022
Number of Shares
2021
Number of Shares
Balance at start of year
Shares issued under Employee Incentive Plans
724,093,661
1,813,788
723,288,869
804,792
Balance at end of year
725,907,449
724,093,661
2022
$’000
197,776
—
197,776
2021
$’000
197,776
—
197,776
(b)
Share Options
The following table shows the movement in options over ordinary shares during the year:
obligations. However, based on past experience, the Group does not expect all employees to take the full amount of accrued leave or
Class
Expiry Date
Exercise
Price
Balance at
Start of Year
Issued
During the Year
Cancelled
During the Year
Exercised
During the
Year
Balance at the
End of the
Year
Executive Share Option Plan
30 Jun 2023
$0.200
18,151,116
Total
18,151,116
—
—
(930,070)
(930,070)
—
—
17,221,046
17,221,046
(c)
Share rights
Under the Group’s Employee Rights Plan, eligible employees may receive rights to shares in Central Petroleum Limited. The rights are
granted in respect of a plan year which commences 1 July each year. The share rights remain unvested until the end of the performance
period, which is three years commencing from the start of each plan year. Except in a limited number of circumstances, eligible employees
must still be in the employment of Central Petroleum Limited as at the vesting date for the rights to vest.
The number of rights to be granted to eligible employees is determined based on the maximum long term incentive amount applicable for
each eligible employee, being either a fixed dollar amount (which are not subject to performance hurdles) or a percentage of the
employee’s base salary, divided by the volume weighted average share price at the start of the plan year.
For those determined by performance hurdles, final vesting percentages reference a combination of absolute total shareholder return and
relative total shareholder return compared to a specific group of exploration and production companies.
Rights issued to non-executive directors during FY2022 were issued under a fee sacrifice arrangement. The number of rights issued was
based on the value of fees sacrificed at a volume weighted average price for the 20 days immediately following the date on which the
Company’s 2021 full year results were released.
2022
$’000
4,500
2021
$’000
36,000
26,309
30,809
18. BORROWINGS
(a)
Current1
Debt facilities
(b)
Non-current1
Debt facilities
1 Details regarding interest bearing liabilities are contained in Note 33(e).
19. PROVISIONS
Employee entitlements (a)
Restoration and rehabilitation (b)
Joint Venture production over-lift (c)
2022
Current Non-Current
$’000
$’000
878
22,120
2,182
4,043
1,512
770
6,325
Total
$’000
4,921
23,632
2,952
2021
Current Non-Current
$’000
$’000
1,084
23,466
2,829
3,184
—
734
3,918
25,180
31,505
27,379
31,297
Total
$’000
4,268
23,466
3,563
(a) The current provision for employee entitlements includes accrued short term incentive plans, severance entitlements, accrued annual
leave and the unconditional entitlements to long service leave where employees have completed the required period of service. The
amounts are presented as current, since the Consolidated Entity does not have an unconditional right to defer settlement for these
require payment in the next 12-months. Current leave obligations that are not expected to be taken or paid within the next
12-months amount to $732,000 (2021: $635,000).
(b) Provisions for future removal and restoration costs are recognised where there is a present obligation and it is probable that an
outflow of economic benefits will be required to settle the obligation. The estimated future obligations include the costs of removing
facilities, abandoning wells and restoring the affected areas.
(c) Under an Interim Gas Balancing Agreement with its joint venture partners, the Group has taken a higher proportion of natural gas
produced from the Mereenie joint venture than its joint venture percentage entitlement. A provision has been recognised to reflect
the expected additional production costs of rebalancing production entitlements between the joint venture partners from future
operations.
Movements in Provisions
Movements in each class of provision during the financial year are set out below:
2022
Carrying amount at start of year
Change in provision charged/(credited) to property,
plant and equipment
Additional provisions charged to profit or loss
Unwinding of discount
Amounts used during the year
Carrying amount at end of year
4,268
2,652
—
—
(1,999)
4,921
Employee
Entitlements
$’000
Restoration &
Rehabilitation
$’000
23,466
Joint Venture
Production
Over-Lift
$’000
3,563
—
118
—
(729)
(275)
65
376
—
Total
$’000
31,297
(275)
2,835
376
(2,728)
23,632
2,952
31,505
74
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
75
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
20. CONTRIBUTED EQUITY (CONTINUED)
23. EARNINGS/(LOSS) PER SHARE
(c)
Share rights (continued)
The table below sets out the maximum number of share rights outstanding at year end and movements for the year.
Class
Expiry Date
Plan Year
Commencing
Balance at
Start of Year
Issued During
the Year
Cancelled
or Lapsed
During the
Year
Exercised
During the
Year
Balance at the
End of the
Year
Long Term Incentive Plans
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee Deferred Share rights1
Employee LTIP rights
Employee LTIP rights
Non-Executive Director rights 2
Director Share Rights
03 Oct 2022
22 May 2024
12 Nov 2024
30 Jun 2024
30 Jun 2025
30 Jun 2025
30 Jun 2026
1 Jul 2017
1 Jul 2018
1 Jul 2018
1 Jul 2019
1 Jul 2019
1 Jul 2020
1 Jul 2021
13,698
6,256,980
1,837,109
6,822,406
3,692,054
9,917,120
—
—
—
—
—
—
—
450,780
(6,849)
(4,089,787)
(1,258,420)
(514,088)
—
(842,320)
(24,588)
—
(1,813,788)
—
—
—
—
—
6,849
353,405
578,689
6,308,318
3,692,054
9,074,800
426,192
30 Jun 2026
1 Jul 2021
—
850,421
—
—
850,421
Total
28,539,367
1,301,201
(6,736,052)
(1,813,788)
21,290,728
per share.
1
In respect of year ended 30 June 2020, certain employees were awarded deferred share rights rather than cash short term incentives. These deferred share rights
have a vesting date of 30 June 2023.
2 Directors had the discretion to sacrifice up to 25% of their FY 2022 Base Directors Fees to earn share rights. These rights vested on 30 June 2022 and may be
exercised any time prior to the expiry date.
The rights do not entitle the holders to participate in any share issue of the Company or any other entity.
21. RESERVES
Share options reserve
Movements:
Balance at start of year
Share based payment costs (a)
Transaction costs
Balance at end of year
2022
$’000
29,094
29,094
1,524
(3)
30,615
2021
$’000
27,238
27,238
1,862
(6)
29,094
(a)
Share based payments are provided to employees under the Employee Rights Plan and Executive Share Option Plan. Refer to
Note 32 for further details of share-based payments.
22. ACCUMULATED LOSSES
Movements in accumulated losses were as follows:
Balance at the start of year
Net profit for the year
Balance at end of year
2022
$’000
(223,181)
21,320
(201,861)
2021
$’000
(223,432)
251
(223,181)
(a)
Basic earnings per share (cents)
(b)
Diluted earnings per share (cents)
(c)
Profit used in earnings per share calculation
Profit attributed to ordinary equity holders ($’000)
(d)
Weighted average number of ordinary shares
Weighted average number of shares used as the denominator in
calculating basic earnings per share
Adjustments for the calculation of diluted earnings per share:
Employee share rights
Weighted average number of shares used as the denominator in
calculating diluted earnings per share
2022
2.94
2.88
2021
0.03
0.03
21,320
251
725,363,955
723,619,673
15,343,575
17,469,319
740,707,530
741,088,992
Options and Rights on issue are considered to be potential ordinary shares and have not been included in the calculation of basic earnings
24. SEGMENT REPORTING
The Group has identified its operating segments based on the internal reports that are reviewed and used by the executive management
team (the chief operating decision makers) in assessing performance and in determining the allocation of resources. The following
operating segments are identified by management based on the nature of the business or venture.
Production and sale of crude oil, natural gas and associated petroleum products from fields that are in the production phase.
Fields under development in preparation for the sale of petroleum products. There were no fields under development during the current
(a)
Producing assets
(b) Development assets
or prior financial year.
(c)
Exploration assets
Exploration and evaluation of permit areas.
(d) Unallocated items
Unallocated items comprise non-segmental items of revenue and expenses and associated assets and liabilities not allocated to operating
segments as they are not considered part of the core operations of any segment.
(e)
Performance monitoring and evaluation
Management monitors the operating results of the operating segments separately for the purpose of making decisions about resource
allocation and performance assessment.
The Consolidated Entity’s operations are wholly in one geographical location, being Australia.
76
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
77
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
20. CONTRIBUTED EQUITY (CONTINUED)
23. EARNINGS/(LOSS) PER SHARE
(c)
Share rights (continued)
The table below sets out the maximum number of share rights outstanding at year end and movements for the year.
Expiry Date
Commencing
Start of Year
the Year
Plan Year
Balance at
Issued During
Cancelled
or Lapsed
During the
Year
Exercised
Balance at the
During the
End of the
Year
Year
Class
Long Term Incentive Plans
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Non-Executive Director rights 2
03 Oct 2022
1 Jul 2017
13,698
(6,849)
22 May 2024
1 Jul 2018
6,256,980
(4,089,787)
(1,813,788)
Employee Deferred Share rights1
30 Jun 2025
1 Jul 2019
3,692,054
12 Nov 2024
1 Jul 2018
1,837,109
30 Jun 2024
1 Jul 2019
6,822,406
30 Jun 2025
1 Jul 2020
9,917,120
30 Jun 2026
1 Jul 2021
—
450,780
(24,588)
—
—
—
—
—
—
(1,258,420)
(514,088)
—
(842,320)
—
—
—
—
—
—
6,849
353,405
578,689
6,308,318
3,692,054
9,074,800
426,192
Director Share Rights
30 Jun 2026
1 Jul 2021
—
850,421
—
—
850,421
Total
28,539,367
1,301,201
(6,736,052)
(1,813,788)
21,290,728
1
In respect of year ended 30 June 2020, certain employees were awarded deferred share rights rather than cash short term incentives. These deferred share rights
2 Directors had the discretion to sacrifice up to 25% of their FY 2022 Base Directors Fees to earn share rights. These rights vested on 30 June 2022 and may be
have a vesting date of 30 June 2023.
exercised any time prior to the expiry date.
The rights do not entitle the holders to participate in any share issue of the Company or any other entity.
21. RESERVES
Share options reserve
Movements:
Balance at start of year
Share based payment costs (a)
Transaction costs
Balance at end of year
22. ACCUMULATED LOSSES
Movements in accumulated losses were as follows:
Balance at the start of year
Net profit for the year
Balance at end of year
2022
$’000
29,094
29,094
1,524
(3)
30,615
2022
$’000
(223,181)
21,320
(201,861)
2021
$’000
27,238
27,238
1,862
(6)
29,094
2021
$’000
(223,432)
251
(223,181)
(a)
Share based payments are provided to employees under the Employee Rights Plan and Executive Share Option Plan. Refer to
Note 32 for further details of share-based payments.
(a)
Basic earnings per share (cents)
(b)
Diluted earnings per share (cents)
(c)
(d)
Profit used in earnings per share calculation
Profit attributed to ordinary equity holders ($’000)
Weighted average number of ordinary shares
Weighted average number of shares used as the denominator in
calculating basic earnings per share
Adjustments for the calculation of diluted earnings per share:
Employee share rights
Weighted average number of shares used as the denominator in
calculating diluted earnings per share
2022
2.94
2.88
2021
0.03
0.03
21,320
251
725,363,955
723,619,673
15,343,575
17,469,319
740,707,530
741,088,992
Options and Rights on issue are considered to be potential ordinary shares and have not been included in the calculation of basic earnings
per share.
24. SEGMENT REPORTING
The Group has identified its operating segments based on the internal reports that are reviewed and used by the executive management
team (the chief operating decision makers) in assessing performance and in determining the allocation of resources. The following
operating segments are identified by management based on the nature of the business or venture.
(a)
Producing assets
Production and sale of crude oil, natural gas and associated petroleum products from fields that are in the production phase.
(b) Development assets
Fields under development in preparation for the sale of petroleum products. There were no fields under development during the current
or prior financial year.
(c)
Exploration assets
Exploration and evaluation of permit areas.
(d) Unallocated items
Unallocated items comprise non-segmental items of revenue and expenses and associated assets and liabilities not allocated to operating
segments as they are not considered part of the core operations of any segment.
(e)
Performance monitoring and evaluation
Management monitors the operating results of the operating segments separately for the purpose of making decisions about resource
allocation and performance assessment.
The Consolidated Entity’s operations are wholly in one geographical location, being Australia.
76
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
77
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
24. SEGMENT REPORTING (CONTINUED)
24. SEGMENT REPORTING (CONTINUED)
(e)
Performance monitoring and evaluation (continued)
(e)
Performance monitoring and evaluation (continued)
2022
Revenue from contracts with customers
Natural gas
Crude oil and condensate
Total revenue from contracts with
customers
Cost of sales
Gross profit
Other income1
Share based employee benefits2
General and administrative expenses
Employee benefits and associated costs
EBITDAX3
Depreciation and amortisation2
Exploration expenditure
Interest revenue
Finance costs
Profit / (loss) before income tax
Taxes
Profit / (loss) for the year
Segment assets
Producing Assets Exploration Assets Unallocated Items
2022
$’000
2022
$’000
2022
$’000
Consolidation
2022
$’000
2021
Producing Assets Exploration Assets Unallocated Items
Consolidation
2021
$’000
2021
$’000
36,255
5,896
42,151
(21,257)
20,894
37,227
—
—
—
58,121
(6,095)
(15,748)
17
(3,979)
32,316
—
32,316
91,954
—
—
—
—
—
10
—
—
—
10
—
(5,899)
—
(41)
(5,930)
—
(5,930)
—
—
—
—
—
—
(1,524)
(1,043)
(1,594)
(4,161)
(684)
—
46
(267)
(5,066)
—
(5,066)
36,255
5,896
42,151
(21,257)
20,894
37,237
(1,524)
(1,043)
(1,594)
53,970
(6,779)
(21,647)
63
(4,287)
21,320
—
21,320
13,038
17,302
122,294
Segment liabilities
(73,212)
(13,741)
(8,811)
(95,764)
Capital expenditure
Property, plant and equipment
Intangibles
Total capital expenditure
9,695
122
9,817
—
—
—
358
55
413
10,053
177
10,230
Includes $36,559,000 profit on disposal of 50% interest in Amadeus Basin producing properties (Refer Note 3(a)).
1
2 Non-cash item.
3 EBITDAX is earnings before interest, taxation, depreciation, amortisation, and exploration expense.
78
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
79
Revenue from contracts with customers
Natural gas
Crude oil and condensate
Total revenue from contracts with
customers
Cost of sales
Gross profit
Other income
Share based employee benefits1
General and administrative expenses
Employee benefits and associated costs
EBITDAX2
Depreciation and amortisation1
Exploration expenditure
Interest revenue
Finance costs
Profit / (loss) before income tax
Taxes
Profit / (loss) for the year
Capital expenditure
Property, plant and equipment
Intangibles
Total capital expenditure
2021
$’000
54,355
5,472
59,827
(28,852)
30,975
7
—
—
—
30,982
(11,783)
(1,012)
21
(5,286)
12,922
—
12,922
11,703
5
11,708
—
—
—
—
—
70
—
—
—
70
—
—
—
—
(6,727)
—
(12)
(6,669)
—
(6,669)
2021
$’000
54,355
5,472
59,827
(28,852)
30,975
79
(1,862)
(924)
(2,180)
26,088
(12,503)
(7,739)
76
(5,671)
251
—
251
11,792
104
11,896
2021
$’000
—
—
—
—
—
2
(1,862)
(924)
(2,180)
(4,964)
(720)
—
55
(373)
(6,002)
—
(6,002)
89
99
188
2022
$’000
Segment assets
133,492
10,264
30,416
174,172
Segment liabilities
(150,774)
(5,462)
(14,247)
(170,483)
Revenue from external customers by geographical location of production:
Non-current assets by geographical location:
Australia
Australia
1 Non-cash item.
2 EBITDAX is earnings before interest, taxation, depreciation, amortisation, and exploration expense.
42,151
59,827
69,907
70,313
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
24. SEGMENT REPORTING (CONTINUED)
24. SEGMENT REPORTING (CONTINUED)
(e)
Performance monitoring and evaluation (continued)
(e)
Performance monitoring and evaluation (continued)
2022
$’000
36,255
5,896
42,151
(21,257)
20,894
37,237
(1,524)
(1,043)
(1,594)
53,970
(6,779)
(21,647)
63
(4,287)
21,320
—
21,320
—
—
—
—
—
—
(1,524)
(1,043)
(1,594)
(4,161)
(684)
—
46
(267)
(5,066)
—
(5,066)
Revenue from contracts with customers
Natural gas
Crude oil and condensate
Total revenue from contracts with
customers
Cost of sales
Gross profit
Other income1
Share based employee benefits2
General and administrative expenses
Employee benefits and associated costs
EBITDAX3
Depreciation and amortisation2
Exploration expenditure
Interest revenue
Finance costs
Profit / (loss) before income tax
Taxes
Profit / (loss) for the year
Capital expenditure
Property, plant and equipment
Intangibles
Total capital expenditure
2022
$’000
36,255
5,896
42,151
(21,257)
20,894
37,227
—
—
—
58,121
(6,095)
(15,748)
17
(3,979)
32,316
—
32,316
91,954
9,695
122
9,817
—
—
—
—
—
10
—
—
—
10
—
—
—
—
(5,899)
—
(41)
(5,930)
—
(5,930)
1
Includes $36,559,000 profit on disposal of 50% interest in Amadeus Basin producing properties (Refer Note 3(a)).
2 Non-cash item.
3 EBITDAX is earnings before interest, taxation, depreciation, amortisation, and exploration expense.
2022
Producing Assets Exploration Assets Unallocated Items
Consolidation
2022
$’000
2022
$’000
2021
Producing Assets Exploration Assets Unallocated Items
2021
$’000
2021
$’000
2021
$’000
Revenue from contracts with customers
Natural gas
Crude oil and condensate
Total revenue from contracts with
customers
Cost of sales
Gross profit
Other income
Share based employee benefits1
General and administrative expenses
Employee benefits and associated costs
EBITDAX2
Depreciation and amortisation1
Exploration expenditure
Interest revenue
Finance costs
Profit / (loss) before income tax
Taxes
Profit / (loss) for the year
54,355
5,472
59,827
(28,852)
30,975
7
—
—
—
30,982
(11,783)
(1,012)
21
(5,286)
12,922
—
12,922
—
—
—
—
—
70
—
—
—
70
—
(6,727)
—
(12)
(6,669)
—
(6,669)
—
—
—
—
—
2
(1,862)
(924)
(2,180)
(4,964)
(720)
—
55
(373)
(6,002)
—
(6,002)
Consolidation
2021
$’000
54,355
5,472
59,827
(28,852)
30,975
79
(1,862)
(924)
(2,180)
26,088
(12,503)
(7,739)
76
(5,671)
251
—
251
Segment assets
13,038
17,302
122,294
Segment liabilities
(73,212)
(13,741)
(8,811)
(95,764)
Segment assets
133,492
10,264
30,416
174,172
Segment liabilities
(150,774)
(5,462)
(14,247)
(170,483)
358
55
413
10,053
177
10,230
Capital expenditure
Property, plant and equipment
Intangibles
Total capital expenditure
11,703
5
11,708
—
—
—
Revenue from external customers by geographical location of production:
Australia
Non-current assets by geographical location:
Australia
1 Non-cash item.
2 EBITDAX is earnings before interest, taxation, depreciation, amortisation, and exploration expense.
89
99
188
2022
$’000
11,792
104
11,896
2021
$’000
42,151
59,827
69,907
70,313
78
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
79
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
24. SEGMENT REPORTING (CONTINUED)
26. RELATED PARTY TRANSACTIONS
(f) Major Customers
Customers with revenue exceeding 10% of the Group’s total hydrocarbon sales revenue are shown below. Revenues from these customers
are reported in the Producing Assets segment.
Largest customer
Second largest customer
Third largest customer
Fourth largest customer
Fifth largest customer
2022
$’000
13,622
7,850
6,478
4,478
4,414
% of Sales
Revenue
32%
19%
15%
11%
10%
2021
$’000
20,028
14,597
10,468
7,803
—
% of Sales
Revenue
33%
24%
17%
13%
—
25. PARENT ENTITY INFORMATION
(a)
Summary financial information
The individual financial summary statements for the Parent Entity show the following aggregate amounts:
Balance Sheet
Current assets
Non-current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Net assets
Shareholders’ equity
Issued capital
Reserves
Accumulated losses
Total equity
Loss for the year
Total comprehensive loss
2022
$’000
23,128
19,162
42,290
(18,129)
(1,550)
(19,679)
22,611
197,776
30,615
(205,780)
22,611
(223)
(223)
2021
$’000
29,855
20,938
50,793
(28,003)
(1,922)
(29,925)
20,868
197,776
29,094
(206,002)
20,868
(3,647)
(3,647)
(b) Guarantees entered into by the Parent Entity
Guarantees have been provided by the Parent Entity to subsidiaries arising out of the course of ordinary operations.
A loan facility exists under which the Parent Entity and non-borrowing subsidiaries have provided guarantees to a financier in relation to
the repayment of monies owing and other performance related obligations of the Borrower typical for a borrowing of this nature. Monies
received through the operation of the Palm Valley, Dingo and Mereenie fields are subject to a proceeds account and can be distributed to
the Parent Entity as available when no default exists. Revenues resulting from operations outside of these assets (such as the Surprise field)
are not subject to a cash sweep or other restrictions under the Facility where no defaults exist.
The consolidated financial statements include the financial statements of Central Petroleum Limited and the subsidiaries listed in the
(a)
Parent Entity
The Parent Entity is Central Petroleum Limited.
(b)
Subsidiaries
following table:
Name of Entity
Merlin Energy Pty Ltd
Central Petroleum Projects Pty Ltd
Helium Australia Pty Ltd
Ordiv Petroleum Pty Ltd
Frontier Oil & Gas Pty Ltd
Central Petroleum Eastern Pty Ltd
Central Geothermal Pty Ltd
Central Petroleum Services Pty Ltd
Central Petroleum PVD Pty Ltd
Central Petroleum (NT) Pty Ltd
Jarl Pty Ltd
Central Petroleum Mereenie Pty Ltd
Central Petroleum Mereenie Unit Trust
Central Petroleum WS (NO 1) Pty Ltd
Central Petroleum WS (NO 2) Pty Ltd
Short-term employee benefits
Post-employment benefits
Long-term benefits
Share based payments
(c) Key management personnel compensation
Place of Incorporation
Class of Shares
Equity Holding
2022
%
2021
%
Western Australia
Western Australia
Victoria
Western Australia
Western Australia
Western Australia
Western Australia
Western Australia
Queensland
Queensland
Queensland
Queensland
N/A
Queensland
Queensland
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Units
Ordinary
Ordinary
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
2022
$
3,531,962
180,208
43,807
1,158,763
2021
$
3,265,233
172,676
43,447
1,112,075
4,914,740
4,593,431
Detailed remuneration disclosures are provided in the remuneration report on pages 34 to 48.
80
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
81
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
24. SEGMENT REPORTING (CONTINUED)
26. RELATED PARTY TRANSACTIONS
Customers with revenue exceeding 10% of the Group’s total hydrocarbon sales revenue are shown below. Revenues from these customers
The Parent Entity is Central Petroleum Limited.
(a)
Parent Entity
(f) Major Customers
are reported in the Producing Assets segment.
25. PARENT ENTITY INFORMATION
(a)
Summary financial information
The individual financial summary statements for the Parent Entity show the following aggregate amounts:
Largest customer
Second largest customer
Third largest customer
Fourth largest customer
Fifth largest customer
Balance Sheet
Current assets
Non-current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Net assets
Shareholders’ equity
Issued capital
Reserves
Accumulated losses
Total equity
Loss for the year
Total comprehensive loss
% of Sales
Revenue
% of Sales
Revenue
2022
$’000
13,622
7,850
6,478
4,478
4,414
2021
$’000
20,028
14,597
10,468
7,803
—
32%
19%
15%
11%
10%
33%
24%
17%
13%
—
2021
$’000
29,855
20,938
50,793
(28,003)
(1,922)
(29,925)
20,868
197,776
29,094
(206,002)
20,868
(3,647)
(3,647)
2022
$’000
23,128
19,162
42,290
(18,129)
(1,550)
(19,679)
22,611
197,776
30,615
(205,780)
22,611
(223)
(223)
(b)
Subsidiaries
The consolidated financial statements include the financial statements of Central Petroleum Limited and the subsidiaries listed in the
following table:
Name of Entity
Place of Incorporation
Class of Shares
Merlin Energy Pty Ltd
Central Petroleum Projects Pty Ltd
Helium Australia Pty Ltd
Ordiv Petroleum Pty Ltd
Frontier Oil & Gas Pty Ltd
Central Petroleum Eastern Pty Ltd
Central Geothermal Pty Ltd
Central Petroleum Services Pty Ltd
Central Petroleum PVD Pty Ltd
Central Petroleum (NT) Pty Ltd
Jarl Pty Ltd
Central Petroleum Mereenie Pty Ltd
Central Petroleum Mereenie Unit Trust
Central Petroleum WS (NO 1) Pty Ltd
Central Petroleum WS (NO 2) Pty Ltd
Western Australia
Western Australia
Victoria
Western Australia
Western Australia
Western Australia
Western Australia
Western Australia
Queensland
Queensland
Queensland
Queensland
N/A
Queensland
Queensland
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Units
Ordinary
Ordinary
(c) Key management personnel compensation
Short-term employee benefits
Post-employment benefits
Long-term benefits
Share based payments
Detailed remuneration disclosures are provided in the remuneration report on pages 34 to 48.
Equity Holding
2022
%
2021
%
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
2022
$
3,531,962
180,208
43,807
1,158,763
2021
$
3,265,233
172,676
43,447
1,112,075
4,914,740
4,593,431
(b) Guarantees entered into by the Parent Entity
Guarantees have been provided by the Parent Entity to subsidiaries arising out of the course of ordinary operations.
A loan facility exists under which the Parent Entity and non-borrowing subsidiaries have provided guarantees to a financier in relation to
the repayment of monies owing and other performance related obligations of the Borrower typical for a borrowing of this nature. Monies
received through the operation of the Palm Valley, Dingo and Mereenie fields are subject to a proceeds account and can be distributed to
the Parent Entity as available when no default exists. Revenues resulting from operations outside of these assets (such as the Surprise field)
are not subject to a cash sweep or other restrictions under the Facility where no defaults exist.
80
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
81
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
27. DEED OF CROSS GUARANTEE
27. DEED OF CROSS GUARANTEE (CONTINUED)
Central Petroleum Limited and its wholly owned subsidiary companies are parties to a deed of cross guarantee under which each company
guarantees the debts of the others. By entering into the deed, the wholly-owned entities have been relieved from the requirement to
prepare a financial report and Directors’ Report under ASIC Corporations (Wholly-owned Companies) Instrument 2016/785.
(b) Consolidated balance sheet
Set out below is a consolidated balance sheet of the closed group as at 30 June.
The parties to the deed of cross guarantee are:
•
•
•
•
•
•
•
•
Central Petroleum Limited
Central Petroleum Projects Pty Ltd
Ordiv Petroleum Pty Ltd
Central Petroleum Eastern Pty Ltd
Central Petroleum Services Pty Ltd
Central Petroleum (NT) Pty Ltd
Central Petroleum Mereenie Pty Ltd
Central Petroleum WS (NO 2) Pty Ltd
• Merlin Energy Pty Ltd
•
•
•
•
Helium Australia Pty Ltd
Frontier Oil & Gas Pty Ltd
Central Geothermal Pty Ltd
Central Petroleum PVD Pty Ltd
•
•
Jarl Pty Ltd
Central Petroleum WS (NO 1) Pty Ltd
The above companies represent a ‘closed group’ for the purposes of the instrument, and as there are no other parties to the deed of cross
guarantee that are controlled by Central Petroleum Limited, they also represent the ‘extended closed group’.
(a) Consolidated statement of profit or loss, statement of comprehensive income and summary of
movements in consolidated retained earnings
Set out below is a consolidated statement of profit or loss, a consolidated statement of comprehensive income and a summary of
movements in consolidated retained earnings of the closed group for the year ended 30 June 2022.
Revenue from the sale of goods
Cost of sales
Gross profit
Other income
Share based employment benefits
General and administrative expenses
Depreciation and amortisation
Employee benefits and associated costs
Exploration expenditure
Finance costs
Loss before income tax
Income tax (expense)/ credit
Profit/(Loss) for the year
Other comprehensive profit/(loss) for the year, net of tax
Total comprehensive profit/(loss) for the year
Accumulated losses at the beginning of the financial year
Profit/(loss) for the year
Accumulated losses at the end of the financial year
2022
$’000
13,645
(5,981)
7,664
29,875
(1,524)
(1,025)
(3,345)
(1,057)
(21,647)
(1,740)
7,201
(10)
7,191
—
7,191
2021
$’000
24,984
(10,342)
14,642
144
(1,862)
(912)
(6,534)
(1,470)
(7,736)
(2,871)
(6,599)
2,547
(4,052)
—
(4,052)
(218,044)
7,191
(213,992)
(4,052)
(210,853)
(218,044)
ASSETS
Current assets
Cash and cash equivalents
Trade and other receivables
Inventories
Assets classified as held for sale
Total current assets
Non-current assets
Property, plant and equipment
Right of use assets
Exploration assets
Intangible assets
Other financial assets
Deferred Tax Assets
Goodwill
Total non-current assets
Trade and other payables
Total assets
LIABILITIES
Current liabilities
Deferred revenue
Borrowings
Lease liabilities
Provisions
Total current liabilities
Non-current liabilities
Deferred revenue
Borrowings
Lease liabilities
Provisions
Total non-current liabilities
Total liabilities
Net assets
EQUITY
Contributed equity
Reserves
Accumulated losses
Total equity
Liabilities directly associated with assets classified as held for sale
2022
$’000
2021
$’000
21,410
21,557
3,075
—
46,042
24,997
858
8,397
314
2,728
5,064
1,953
44,311
90,353
22,958
992
2,821
386
5,098
—
32,255
11,824
14,266
543
13,927
40,560
72,815
17,538
197,776
30,615
(210,853)
17,538
37,153
3,495
899
28,519
70,066
25,733
1,366
8,397
295
2,645
6,291
1,953
46,680
116,746
22,115
992
16,034
492
3,184
18,399
61,216
10,797
21,019
922
13,966
46,704
107,920
8,826
197,776
29,094
(218,044)
8,826
82
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
83
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
27. DEED OF CROSS GUARANTEE
27. DEED OF CROSS GUARANTEE (CONTINUED)
Central Petroleum Limited and its wholly owned subsidiary companies are parties to a deed of cross guarantee under which each company
guarantees the debts of the others. By entering into the deed, the wholly-owned entities have been relieved from the requirement to
prepare a financial report and Directors’ Report under ASIC Corporations (Wholly-owned Companies) Instrument 2016/785.
(b) Consolidated balance sheet
Set out below is a consolidated balance sheet of the closed group as at 30 June.
2022
$’000
2021
$’000
ASSETS
Current assets
Cash and cash equivalents
Trade and other receivables
Inventories
Assets classified as held for sale
Total current assets
Non-current assets
Property, plant and equipment
Right of use assets
Exploration assets
Intangible assets
Other financial assets
Deferred Tax Assets
Goodwill
Total non-current assets
Total assets
LIABILITIES
Current liabilities
Trade and other payables
Deferred revenue
Borrowings
Lease liabilities
Provisions
Liabilities directly associated with assets classified as held for sale
Total current liabilities
Non-current liabilities
Deferred revenue
Borrowings
Lease liabilities
Provisions
Total non-current liabilities
Total liabilities
Net assets
EQUITY
Contributed equity
Reserves
Accumulated losses
Total equity
21,410
21,557
3,075
—
46,042
24,997
858
8,397
314
2,728
5,064
1,953
44,311
90,353
22,958
992
2,821
386
5,098
—
32,255
11,824
14,266
543
13,927
40,560
72,815
17,538
197,776
30,615
(210,853)
17,538
37,153
3,495
899
28,519
70,066
25,733
1,366
8,397
295
2,645
6,291
1,953
46,680
116,746
22,115
992
16,034
492
3,184
18,399
61,216
10,797
21,019
922
13,966
46,704
107,920
8,826
197,776
29,094
(218,044)
8,826
The parties to the deed of cross guarantee are:
•
•
•
•
•
•
•
•
Central Petroleum Limited
Central Petroleum Projects Pty Ltd
Ordiv Petroleum Pty Ltd
Central Petroleum Eastern Pty Ltd
Central Petroleum Services Pty Ltd
Central Petroleum (NT) Pty Ltd
Central Petroleum Mereenie Pty Ltd
Central Petroleum WS (NO 2) Pty Ltd
• Merlin Energy Pty Ltd
•
•
•
•
•
•
Helium Australia Pty Ltd
Frontier Oil & Gas Pty Ltd
Central Geothermal Pty Ltd
Central Petroleum PVD Pty Ltd
Jarl Pty Ltd
Central Petroleum WS (NO 1) Pty Ltd
The above companies represent a ‘closed group’ for the purposes of the instrument, and as there are no other parties to the deed of cross
guarantee that are controlled by Central Petroleum Limited, they also represent the ‘extended closed group’.
(a) Consolidated statement of profit or loss, statement of comprehensive income and summary of
movements in consolidated retained earnings
Set out below is a consolidated statement of profit or loss, a consolidated statement of comprehensive income and a summary of
movements in consolidated retained earnings of the closed group for the year ended 30 June 2022.
Revenue from the sale of goods
Cost of sales
Gross profit
Other income
Share based employment benefits
General and administrative expenses
Depreciation and amortisation
Employee benefits and associated costs
Exploration expenditure
Finance costs
Loss before income tax
Income tax (expense)/ credit
Profit/(Loss) for the year
Other comprehensive profit/(loss) for the year, net of tax
Total comprehensive profit/(loss) for the year
Accumulated losses at the beginning of the financial year
Profit/(loss) for the year
Accumulated losses at the end of the financial year
2022
$’000
13,645
(5,981)
7,664
29,875
(1,524)
(1,025)
(3,345)
(1,057)
(21,647)
(1,740)
7,201
(10)
7,191
—
7,191
2021
$’000
24,984
(10,342)
14,642
144
(1,862)
(912)
(6,534)
(1,470)
(7,736)
(2,871)
(6,599)
2,547
(4,052)
—
(4,052)
(218,044)
7,191
(213,992)
(4,052)
(210,853)
(218,044)
82
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
83
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
28. RECONCILIATION OF PROFIT AFTER INCOME TAX TO NET CASH
29. CASH FLOW INFORMATION (CONTINUED)
FLOWS FROM OPERATING ACTIVITIES
Profit after income tax
Adjustments for:
Depreciation and amortisation
Lease incentive
Profit on disposal of assets
Exploration costs funded by Joint Venture partners as part of deferred
consideration from sale of Amadeus Basin producing properties
Share-based payments
Restatement of financial assets at amortised cost
Financing costs and interest (non-cash)
Changes in assets and liabilities relating to operating activities:
Decrease/(Increase) in trade and other receivables
Increase in inventories
Increase in trade and other payables
(Decrease)/Increase in deferred revenue
Increase in provisions
Net cash inflow from operations
29. CASH FLOW INFORMATION
(a)
Non-cash investing and financing activities
2022
$’000
21,320
6,779
30
(36,559)
7,572
1,524
665
485
358
(2,330)
7,781
(4,155)
170
3,640
2021
$’000
251
12,503
—
(6)
—
1,862
—
1,747
(515)
(93)
1,395
6,850
142
24,136
Following completion of the disposal of 50% of the Group’s interests in the Amadeus Basin producing properties on 1 October 2021, the
purchasers have funded $2,040,000 (2021: Nil) of the Group’s share of costs for the acquisition of property, plant and equipment in
FY2022. These amounts form part of the deferred consideration component of the sale proceeds (refer Note 3 (a)).
(ii)
Palm Valley Gas Field Gas Price Bonus
Non-cash investing and financing activities disclosed in other notes are:
Acquisition of right of use assets – Note 12(a); and
Options and rights issued to employees under short and long term incentive plans – Note 32.
•
•
(b) Net debt reconciliation
This section provides an analysis of those liabilities for which cash flows have been or will be classified as financing activities in the
statement of cash flows. Cash balances included as current assets on the balance sheet are included as the Group considers these to form
part of its net debt.
Net debt
Cash and cash equivalents (including cash classified as held for sale)
Borrowings and leases – repayable within one year1
Borrowings and leases – repayable after one year1
Net debt
Cash
Gross Debt – fixed interest rates
Gross debt – variable interest rates
Net debt
1
Including leases associated with assets classified as held for sale at 30 June 2021.
2022
$’000
21,647
(4,913)
(26,897)
(10,163)
21,647
(1,001)
(30,809)
(10,163)
2021
$’000
37,165
(36,543)
(31,925)
(31,303)
37,165
(1,659)
(66,809)
(31,303)
(b) Net debt reconciliation (continued)
Movement in Net Debt
Net debt 1 July 2020
Cash flows
Non-cash lease adjustments
Other non-cash movements
Net debt 30 June 2021
Cash flows
Non-cash lease adjustments
Net debt 30 June 2022
30. CONTINGENCIES
(a) Contingent liabilities
(i)
Exploration Permits
Other Assets
Liabilities from Financing Activities
Cash
$’000
Borrowings
$’000
25,918
11,247
—
—
(70,773)
4,000
—
(36)
37,165
(66,809)
(15,518)
—
36,000
—
Leases
$’000
(1,226)
622
(1,055)
—
(1,659)
561
97
Total
$’000
(46,081)
15,869
(1,055)
(36)
(31,303)
21,043
97
21,647
(30,809)
(1,001)
(10,163)
The Consolidated Entity had contingent liabilities at 30 June 2022 in respect of certain joint arrangement payments. As partial
consideration under the terms of the purchase agreement for EP105, there is a requirement to pay the vendor the sum of
$1,000,000 (2021: $1,000,000) within 12-months following the commencement of any future commercial production from the
permits. No commercial production is currently forecast from these permits.
Under the Share Sale and Purchase Deed entered into with Magellan Petroleum Australia Pty Limited (Magellan) in February 2014
for the purchase of Palm Valley and Dingo gas fields and related assets, Central Petroleum Limited is obligated to pay to Magellan a
Gas Price Bonus where the weighted average price of gas sold from the Palm Valley gas field during a Contract Year exceeds certain
price hurdles during a period of 15 years following Completion of the Agreement.
The Gas Price Bonus Amount is calculated as 25% of the difference between the weighted average price of gas actually sold
(excluding GST and other costs) in a Contract Year and the gas price bonus hurdle applicable to that Contract Year (after adjusting
for CPI), multiplied by the actual volume of gas originating and sold from the Palm Valley gas field. The weighted average price of
gas sold from the Palm Valley gas field is currently below the Gas Price Bonus hurdle price and therefore no gas price bonus is
payable at this time. Based on current reserves and production profiles for the Palm Valley Gas Field, and current Northern
Territory gas market conditions, it is not anticipated that a gas price bonus will be payable over the relevant term and have
therefore ascribed a $nil value to this contingent liability. Should access to additional reserves and significantly higher priced
markets eventuate, this contingent liability will be reviewed. Importantly, any future payment of the Gas Price Bonus would only
occur where sales and revenues from the Palm Valley gas field materially exceed Central’s acquisition assumptions.
84
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
85
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
28. RECONCILIATION OF PROFIT AFTER INCOME TAX TO NET CASH
29. CASH FLOW INFORMATION (CONTINUED)
FLOWS FROM OPERATING ACTIVITIES
Profit after income tax
Adjustments for:
Depreciation and amortisation
Lease incentive
Profit on disposal of assets
Exploration costs funded by Joint Venture partners as part of deferred
consideration from sale of Amadeus Basin producing properties
Share-based payments
Restatement of financial assets at amortised cost
Financing costs and interest (non-cash)
Changes in assets and liabilities relating to operating activities:
Decrease/(Increase) in trade and other receivables
Increase in inventories
Increase in trade and other payables
(Decrease)/Increase in deferred revenue
Increase in provisions
Net cash inflow from operations
29. CASH FLOW INFORMATION
(a)
Non-cash investing and financing activities
(b) Net debt reconciliation
part of its net debt.
Net debt
Net debt
Cash
Net debt
Gross Debt – fixed interest rates
Gross debt – variable interest rates
Cash and cash equivalents (including cash classified as held for sale)
Borrowings and leases – repayable within one year1
Borrowings and leases – repayable after one year1
1
Including leases associated with assets classified as held for sale at 30 June 2021.
2022
$’000
21,320
6,779
30
(36,559)
7,572
1,524
665
485
358
(2,330)
7,781
(4,155)
170
3,640
2022
$’000
21,647
(4,913)
(26,897)
(10,163)
21,647
(1,001)
(30,809)
(10,163)
2021
$’000
251
12,503
—
(6)
1,862
—
—
1,747
(515)
(93)
1,395
6,850
142
24,136
2021
$’000
37,165
(36,543)
(31,925)
(31,303)
37,165
(1,659)
(66,809)
(31,303)
Following completion of the disposal of 50% of the Group’s interests in the Amadeus Basin producing properties on 1 October 2021, the
purchasers have funded $2,040,000 (2021: Nil) of the Group’s share of costs for the acquisition of property, plant and equipment in
FY2022. These amounts form part of the deferred consideration component of the sale proceeds (refer Note 3 (a)).
Non-cash investing and financing activities disclosed in other notes are:
Acquisition of right of use assets – Note 12(a); and
•
•
Options and rights issued to employees under short and long term incentive plans – Note 32.
This section provides an analysis of those liabilities for which cash flows have been or will be classified as financing activities in the
statement of cash flows. Cash balances included as current assets on the balance sheet are included as the Group considers these to form
(b) Net debt reconciliation (continued)
Movement in Net Debt
Net debt 1 July 2020
Cash flows
Non-cash lease adjustments
Other non-cash movements
Net debt 30 June 2021
Cash flows
Non-cash lease adjustments
Net debt 30 June 2022
30. CONTINGENCIES
(a) Contingent liabilities
(i)
Exploration Permits
Other Assets
Liabilities from Financing Activities
Cash
$’000
Borrowings
$’000
25,918
11,247
—
—
37,165
(15,518)
—
(70,773)
4,000
—
(36)
(66,809)
36,000
—
Leases
$’000
(1,226)
622
(1,055)
—
(1,659)
561
97
Total
$’000
(46,081)
15,869
(1,055)
(36)
(31,303)
21,043
97
21,647
(30,809)
(1,001)
(10,163)
The Consolidated Entity had contingent liabilities at 30 June 2022 in respect of certain joint arrangement payments. As partial
consideration under the terms of the purchase agreement for EP105, there is a requirement to pay the vendor the sum of
$1,000,000 (2021: $1,000,000) within 12-months following the commencement of any future commercial production from the
permits. No commercial production is currently forecast from these permits.
(ii)
Palm Valley Gas Field Gas Price Bonus
Under the Share Sale and Purchase Deed entered into with Magellan Petroleum Australia Pty Limited (Magellan) in February 2014
for the purchase of Palm Valley and Dingo gas fields and related assets, Central Petroleum Limited is obligated to pay to Magellan a
Gas Price Bonus where the weighted average price of gas sold from the Palm Valley gas field during a Contract Year exceeds certain
price hurdles during a period of 15 years following Completion of the Agreement.
The Gas Price Bonus Amount is calculated as 25% of the difference between the weighted average price of gas actually sold
(excluding GST and other costs) in a Contract Year and the gas price bonus hurdle applicable to that Contract Year (after adjusting
for CPI), multiplied by the actual volume of gas originating and sold from the Palm Valley gas field. The weighted average price of
gas sold from the Palm Valley gas field is currently below the Gas Price Bonus hurdle price and therefore no gas price bonus is
payable at this time. Based on current reserves and production profiles for the Palm Valley Gas Field, and current Northern
Territory gas market conditions, it is not anticipated that a gas price bonus will be payable over the relevant term and have
therefore ascribed a $nil value to this contingent liability. Should access to additional reserves and significantly higher priced
markets eventuate, this contingent liability will be reviewed. Importantly, any future payment of the Gas Price Bonus would only
occur where sales and revenues from the Palm Valley gas field materially exceed Central’s acquisition assumptions.
84
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
85
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
31. COMMITMENTS
(a) Capital commitments
The Consolidated Entity has the following capital expenditure commitments:
The following amounts are due:
Within one year
(b) Exploration commitments
2022
$’000
2021
$’000
982
982
3,159
3,159
32. SHARE BASED PAYMENTS (CONTINUED)
(b) Rights to shares — Short Term Incentive Plan
Under the Group’s Short Term Incentive Plan, the Board may issue share rights in lieu of cash payments. No share rights were issued in
respect of the Short Term Incentive Plan during the 2022 year.
Grant Date
Plan Year End
Start of Year
Rights Granted
Value Per Right
During the Year
Balance at
Number of
Average Fair
Exercised
Cancelled or
Forfeited
Balance at
End of Year
11 Nov 2020 30 Jun 20201
3,692,054
—
$0.130
—
3,692,054
The Consolidated Entity has the following minimum exploration expenditure commitments:
11 Nov 2020 30 Jun 20201
—
3,692,054
$0.130
—
3,692,054
The following amounts are due:
Within one year
Later than one year but not later than three years
Later than three years but not later than five years
39,398
38,799
—
78,197
11,742
56,400
—
68,142
These commitments may be varied in the future as a result of renegotiations of the terms of exploration permits. In the petroleum industry
it is common practice for entities to farm-out, transfer or sell a portion of their rights to third parties or relinquish (whole or part of the
permit) and, as a result, obligations may be reduced or extinguished.
As announced on 9 February 2022, the Group has entered into a farmout agreement with Peak Helium (Amadeus Basin) Pty Ltd in respect
of certain exploration permits. Once completed, the Group’s total exploration commitments as shown above will reduce from $78,197,000
to $59,359,000.
32. SHARE BASED PAYMENTS
(a)
Employee options
An Executive Share Option Plan operates to provide incentives for key executives. Participation in the plan is at the Board’s discretion.
Details of options issued under the plan are shown below.
Grant Date
Expiry Date
Balance at
Start of
Year
Granted During
the Year
Exercise
Price
Average
Fair Value
Per Option
Cancelled or
Expired During
the Year
Balance at End
of Year
Vested and
Exercisable
2022
20 Aug 2019
07 Nov 2019
Totals
30 Jun 2023
30 Jun 2023
13,046,116
5,105,000
18,151,116
Weighted average exercise price
$0.20
2021
20 Aug 2019
07 Nov 2019
30 Jun 2023
30 Jun 2023
13,046,116
5,105,000
Totals
18,151,116
Weighted average exercise price
$0.20
—
—
—
—
—
—
—
—
$0.20
$0.20
$0.120
$0.087
(930,070)
—
12,116,046
5,105,000
$0.111
(930,070)
17,221,046
$0.20
$0.20
$0.120
$0.087
$0.111
—
—
—
—
—
$0.20
13,046,116
5,105,000
18,151,116
$0.20
—
—
—
—
—
—
—
—
The weighted average remaining contractual life at 30 June 2022 was 1 year (2021: 2 years). The values of Executive Options are calculated
at the date of grant using a Black Scholes valuation.
2022
2021
2022
—
—
1 Share rights in respect of the performance period ended 30 June 2020 have a deferred vesting date of 30 June 2023.
The weighted average fair value of share rights issued under the Short Term Incentive Plan during the year was nil (2021: $0.13).
(c) Rights to shares — Non-Executive Directors Offer
Under the FY2022 Non-Executive Director offer, Directors could agree to receive a maximum of 25% of their FY2022 Base Fee in the form of
Share Rights. By agreeing to the offer, the Directors agreed to waive any entitlement to receive cash fees to the extent of the value of the
Share Rights granted. The Share rights automatically vested on 30 June 2022. The following Non-Executive Director Share rights were
granted during the 2022 year:
Grant Date
Plan Year End
Start of Year
Rights Granted
Value Per Right
During the Year
Balance at
Number of
Average Fair
Exercised
Cancelled or
Forfeited
Vested and
exercisable at
End of Year
23 Nov 2021 30 Jun 2022
—
850,421
$0.115
—
—
850,421
(d) Rights to shares — Executive Incentive Plan (EIP)
As at 30 June 2022, no share rights had been granted under the EIP. Share rights, as part of the FY2022 EIP are expected to be granted
during FY2023. The number of rights to be granted is determined based on Central Petroleum Limited’s share price for the 20-days after
release or the June 2022 quarterly report (9.9 cents per right). The grant date is yet to be determined.
(e) Rights to shares — Long Term Incentive Plans
Under the Group’s Employee Rights Plan, eligible employees may receive rights to shares of Central Petroleum Limited. The rights are
granted in respect of a plan year which commences 1 July each year. The share rights remain unvested for three years commencing from
the start of each plan year. Except in limited circumstances, eligible employees must still be in the employment of Central Petroleum
Limited as at the vesting date for the rights to vest.
The number of rights to be granted to eligible employees is determined based on the maximum long term incentive amount applicable for
each employee, being either a fixed dollar amount or a percentage of the employee’s base salary, divided by the volume weighted average
share price at the start of the plan year.
Final vesting percentages for those employees on a percentage based plan are determined by a combination of performance hurdles in
respect of a combination of absolute total shareholder return and relative total shareholder return compared to a specific group of
exploration and production companies.
expected to be granted:
Share based payment expense for the year includes amounts expensed in respect of the following number of rights either granted or
86
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
87
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
31. COMMITMENTS
(a) Capital commitments
The following amounts are due:
Within one year
The Consolidated Entity has the following capital expenditure commitments:
(b) Exploration commitments
The Consolidated Entity has the following minimum exploration expenditure commitments:
The following amounts are due:
Within one year
Later than one year but not later than three years
Later than three years but not later than five years
2022
$’000
2021
$’000
982
982
3,159
3,159
39,398
38,799
—
78,197
11,742
56,400
—
68,142
These commitments may be varied in the future as a result of renegotiations of the terms of exploration permits. In the petroleum industry
it is common practice for entities to farm-out, transfer or sell a portion of their rights to third parties or relinquish (whole or part of the
permit) and, as a result, obligations may be reduced or extinguished.
As announced on 9 February 2022, the Group has entered into a farmout agreement with Peak Helium (Amadeus Basin) Pty Ltd in respect
of certain exploration permits. Once completed, the Group’s total exploration commitments as shown above will reduce from $78,197,000
to $59,359,000.
32. SHARE BASED PAYMENTS
(a)
Employee options
An Executive Share Option Plan operates to provide incentives for key executives. Participation in the plan is at the Board’s discretion.
Details of options issued under the plan are shown below.
Grant Date
Expiry Date
Balance at
Average
Cancelled or
Start of
Granted During
Exercise
Fair Value
Expired During
Balance at End
Year
the Year
Price
Per Option
the Year
of Year
Vested and
Exercisable
2022
20 Aug 2019
07 Nov 2019
Totals
30 Jun 2023
30 Jun 2023
13,046,116
5,105,000
18,151,116
Weighted average exercise price
$0.20
2021
Totals
20 Aug 2019
07 Nov 2019
30 Jun 2023
30 Jun 2023
13,046,116
5,105,000
18,151,116
Weighted average exercise price
$0.20
—
—
—
—
—
—
—
—
$0.20
$0.20
$0.120
$0.087
(930,070)
12,116,046
—
5,105,000
$0.111
(930,070)
17,221,046
$0.20
$0.20
$0.120
$0.087
$0.111
—
—
—
—
—
$0.20
13,046,116
5,105,000
18,151,116
$0.20
—
—
—
—
—
—
—
—
The weighted average remaining contractual life at 30 June 2022 was 1 year (2021: 2 years). The values of Executive Options are calculated
at the date of grant using a Black Scholes valuation.
32. SHARE BASED PAYMENTS (CONTINUED)
(b) Rights to shares — Short Term Incentive Plan
Under the Group’s Short Term Incentive Plan, the Board may issue share rights in lieu of cash payments. No share rights were issued in
respect of the Short Term Incentive Plan during the 2022 year.
Grant Date
Plan Year End
2022
11 Nov 2020 30 Jun 20201
2021
11 Nov 2020 30 Jun 20201
Balance at
Start of Year
Number of
Rights Granted
Average Fair
Value Per Right
Exercised
During the Year
Cancelled or
Forfeited
Balance at
End of Year
3,692,054
—
$0.130
—
3,692,054
$0.130
—
—
—
3,692,054
—
3,692,054
1 Share rights in respect of the performance period ended 30 June 2020 have a deferred vesting date of 30 June 2023.
The weighted average fair value of share rights issued under the Short Term Incentive Plan during the year was nil (2021: $0.13).
(c) Rights to shares — Non-Executive Directors Offer
Under the FY2022 Non-Executive Director offer, Directors could agree to receive a maximum of 25% of their FY2022 Base Fee in the form of
Share Rights. By agreeing to the offer, the Directors agreed to waive any entitlement to receive cash fees to the extent of the value of the
Share Rights granted. The Share rights automatically vested on 30 June 2022. The following Non-Executive Director Share rights were
granted during the 2022 year:
Grant Date
Plan Year End
2022
23 Nov 2021 30 Jun 2022
Balance at
Start of Year
Number of
Rights Granted
Average Fair
Value Per Right
Exercised
During the Year
Cancelled or
Forfeited
Vested and
exercisable at
End of Year
—
850,421
$0.115
—
—
850,421
(d) Rights to shares — Executive Incentive Plan (EIP)
As at 30 June 2022, no share rights had been granted under the EIP. Share rights, as part of the FY2022 EIP are expected to be granted
during FY2023. The number of rights to be granted is determined based on Central Petroleum Limited’s share price for the 20-days after
release or the June 2022 quarterly report (9.9 cents per right). The grant date is yet to be determined.
(e) Rights to shares — Long Term Incentive Plans
Under the Group’s Employee Rights Plan, eligible employees may receive rights to shares of Central Petroleum Limited. The rights are
granted in respect of a plan year which commences 1 July each year. The share rights remain unvested for three years commencing from
the start of each plan year. Except in limited circumstances, eligible employees must still be in the employment of Central Petroleum
Limited as at the vesting date for the rights to vest.
The number of rights to be granted to eligible employees is determined based on the maximum long term incentive amount applicable for
each employee, being either a fixed dollar amount or a percentage of the employee’s base salary, divided by the volume weighted average
share price at the start of the plan year.
Final vesting percentages for those employees on a percentage based plan are determined by a combination of performance hurdles in
respect of a combination of absolute total shareholder return and relative total shareholder return compared to a specific group of
exploration and production companies.
Share based payment expense for the year includes amounts expensed in respect of the following number of rights either granted or
expected to be granted:
86
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
87
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
32. SHARE BASED PAYMENTS (CONTINUED)
32. SHARE BASED PAYMENTS (CONTINUED)
(e) Rights to shares — Long Term Incentive Plans (continued)
(e) Rights to shares — Long Term Incentive Plans (continued)
Plan Year
End
Balance at
Start of Year
Granted
During the Year
Average
Fair Value
Per Right
Exercised
During the Year
Cancelled or
Forfeited
During the Year
Balance at
End of Year
Grant Date
End
Plan Year
Balance at
Granted
Start of Year
During the Year
Average
Fair Value
Per Right
Exercised
Cancelled or
Forfeited
During the Year
During the Year
Balance at
End of Year
Grant Date
2022
17 Aug 2021 30 Jun 2022
11 Nov 2020 30 Jun 2020
18 Sep 2020 30 Jun 2018
30 Jun 2021
24 Jul 2020
24 Jul 2020
30 Jun 2021
30 Jun 2020
24 Jul 2020
07 Nov 2019 30 Jun 2019
23 Aug 2019 30 Jun 2020
23 Aug 2019 30 Jun 2020
09 May 2019 30 Jun 2019
17 Apr 2019 30 Jun 2019
17 Apr 2019 30 Jun 2019
24 Sep 2019 30 Jun 2019
24 Sep 2019 30 Jun 2019
01 Sep 2017 30 Jun 2018
—
3,692,054
1,198
9,417,632
499,488
30,545
1,837,109
311,019
6,480,842
756,584
28,793
2,566
5,176,154
292,883
12,500
450,780
—
—
—
—
—
—
—
—
—
—
—
—
—
—
$0.105
$0.130
$0.130
$0.065
$0.089
$0.089
$0.119
$0.190
$0.155
$0.101
$0.111
$0.150
$0.087
$0.120
$0.115
—
—
—
—
—
—
—
—
—
(31,848)
(9,069)
(2,566)
(1,549,532)
(220,773)
—
(24,588)
—
—
(796,972)
(45,348)
—
(1,258,420)
(36,900)
(477,188)
(696,724)
(19,724)
—
(3,367,216)
(6,123)
(6,849)
426,192
3,692,054
1,198
8,620,660
454,140
30,545
578,689
274,119
6,003,654
28,012
—
—
259,406
65,987
5,651
Totals
28,539,367
450,780
(1,813,788)
(6,736,052)
20,440,307
The weighted average fair value of share rights granted under the Long Term Incentive Plan during the year was $0.105 (2021: $0.084).
The weighted average remaining contractual life of outstanding share rights at the end of the year was 2.7 years (2021: 3.5 years).
01 Sep 2017 30 Jun 2018
4,400,423
The fair values of deferred share rights granted are valued using methodology that takes into account market and peer performance
hurdles if applicable. The value of share rights with performance hurdles are calculated at the date of grant using a Black Scholes valuation
model and Monte Carlo simulations and an agreed comparator group to assess relative total shareholder return. Other share rights are
valued at the value of an equivalent ordinary share at the grant date.
—
—
—
—
—
3,692,054
20,271
9,417,632
499,488
30,545
07 Nov 2019 30 Jun 2019
1,837,109
2021
11 Nov 2020 30 Jun 2020
18 Sep 2020 30 Jun 2018
24 Jul 2020
30 Jun 2021
24 Jul 2020
30 Jun 2021
24 Jul 2020
30 Jun 2020
13 Sep 2019 30 Jun 2017
23 Aug 2019 30 Jun 2020
23 Aug 2019 30 Jun 2020
09 May 2019 30 Jun 2019
17 Apr 2019 30 Jun 2019
17 Apr 2019 30 Jun 2019
24 Sep 2019 30 Jun 2019
24 Sep 2019 30 Jun 2019
02 Oct 2018 30 Jun 2016
27 Jun 2018 30 Jun 2018
16 May 2018 30 Jun 2018
16 May 2018 30 Jun 2018
01 Sep 2017 30 Jun 2018
20 Oct 2016 30 Jun 2017
20 Oct 2016 30 Jun 2017
09 Nov 2015 30 Jun 2016
50,700
348,708
7,004,467
768,542
49,321
2,566
5,302,029
321,940
639
135,920
6,562
10,306
201,222
517,575
11,111
6,666
$0.130
$0.130
$0.065
$0.089
$0.089
$0.119
$0.150
$0.190
$0.155
$0.101
$0.111
$0.150
$0.087
$0.120
$0.067
$0.102
$0.126
$0.175
$0.081
$0.115
$0.106
$0.135
$0.184
(19,073)
(50,700)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(639)
(10,306)
(188,722)
(517,575)
(11,111)
(6,666)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(37,689)
(523,625)
(11,958)
(20,528)
(125,875)
(29,057)
(135,920)
(6,562)
(4,400,423)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Totals
20,975,806
13,659,990
(804,792)
(5,291,637)
28,539,367
No rights were granted to key management personnel during FY2022. The following factors and assumptions were used in determining the
fair value of share rights granted to key management personnel during FY2021:
Grant Date Expiry Date
24 Jul 20201
30 Jun 2025
11 Nov 20202 30 Jun 2025
Fair Value
Per Right
Exercise
Price
Price of Shares
at Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
$0.065
$0.130
Nil
Nil
$0.089
$0.130
72%
N/A
0.43%
N/A
1
LTIP Rights for the plan year commencing 1 July 2020.
2 Deferred share rights issued in lieu of cash under the short term incentive plan for the year commencing 1 July 2019.
(f)
Expenses arising from share-based payment transactions
Total expenses arising from share-based transactions recognised during the year were:
Share Rights issued to employees
2022
$
2021
$
1,524,197
1,862,072
3,692,054
1,198
9,417,632
499,488
30,545
1,837,109
—
311,019
6,480,842
756,584
28,793
2,566
5,176,154
292,883
12,500
—
—
—
—
—
—
—
—
—
—
88
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
89
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
32. SHARE BASED PAYMENTS (CONTINUED)
32. SHARE BASED PAYMENTS (CONTINUED)
(e) Rights to shares — Long Term Incentive Plans (continued)
(e) Rights to shares — Long Term Incentive Plans (continued)
Grant Date
End
Plan Year
Balance at
Granted
Start of Year
During the Year
Average
Fair Value
Per Right
Exercised
Cancelled or
Forfeited
During the Year
During the Year
Balance at
End of Year
Grant Date
Plan Year
End
Balance at
Start of Year
Granted
During the Year
Average
Fair Value
Per Right
Exercised
During the Year
Cancelled or
Forfeited
During the Year
Balance at
End of Year
2022
17 Aug 2021 30 Jun 2022
11 Nov 2020 30 Jun 2020
18 Sep 2020 30 Jun 2018
24 Jul 2020
30 Jun 2021
24 Jul 2020
30 Jun 2021
24 Jul 2020
30 Jun 2020
07 Nov 2019 30 Jun 2019
23 Aug 2019 30 Jun 2020
23 Aug 2019 30 Jun 2020
09 May 2019 30 Jun 2019
17 Apr 2019 30 Jun 2019
17 Apr 2019 30 Jun 2019
24 Sep 2019 30 Jun 2019
01 Sep 2017 30 Jun 2018
3,692,054
1,198
9,417,632
499,488
30,545
1,837,109
311,019
6,480,842
756,584
28,793
2,566
292,883
12,500
—
450,780
—
—
—
—
—
—
—
—
—
—
—
—
—
—
$0.105
$0.130
$0.130
$0.065
$0.089
$0.089
$0.119
$0.190
$0.155
$0.101
$0.111
$0.150
$0.087
$0.120
$0.115
—
—
—
—
—
—
—
—
—
(31,848)
(9,069)
(2,566)
(220,773)
—
(24,588)
—
—
—
(796,972)
(45,348)
(1,258,420)
(36,900)
(477,188)
(696,724)
(19,724)
—
(6,123)
(6,849)
426,192
3,692,054
1,198
8,620,660
454,140
30,545
578,689
274,119
6,003,654
28,012
—
—
259,406
65,987
5,651
24 Sep 2019 30 Jun 2019
5,176,154
(1,549,532)
(3,367,216)
Totals
28,539,367
450,780
(1,813,788)
(6,736,052)
20,440,307
The weighted average fair value of share rights granted under the Long Term Incentive Plan during the year was $0.105 (2021: $0.084).
The weighted average remaining contractual life of outstanding share rights at the end of the year was 2.7 years (2021: 3.5 years).
The fair values of deferred share rights granted are valued using methodology that takes into account market and peer performance
hurdles if applicable. The value of share rights with performance hurdles are calculated at the date of grant using a Black Scholes valuation
model and Monte Carlo simulations and an agreed comparator group to assess relative total shareholder return. Other share rights are
valued at the value of an equivalent ordinary share at the grant date.
2021
11 Nov 2020 30 Jun 2020
18 Sep 2020 30 Jun 2018
30 Jun 2021
24 Jul 2020
30 Jun 2021
24 Jul 2020
24 Jul 2020
30 Jun 2020
07 Nov 2019 30 Jun 2019
13 Sep 2019 30 Jun 2017
23 Aug 2019 30 Jun 2020
23 Aug 2019 30 Jun 2020
09 May 2019 30 Jun 2019
17 Apr 2019 30 Jun 2019
17 Apr 2019 30 Jun 2019
24 Sep 2019 30 Jun 2019
24 Sep 2019 30 Jun 2019
02 Oct 2018 30 Jun 2016
27 Jun 2018 30 Jun 2018
16 May 2018 30 Jun 2018
16 May 2018 30 Jun 2018
01 Sep 2017 30 Jun 2018
01 Sep 2017 30 Jun 2018
20 Oct 2016 30 Jun 2017
20 Oct 2016 30 Jun 2017
09 Nov 2015 30 Jun 2016
—
—
—
—
—
1,837,109
50,700
348,708
7,004,467
768,542
49,321
2,566
5,302,029
321,940
639
135,920
6,562
10,306
4,400,423
201,222
517,575
11,111
6,666
3,692,054
20,271
9,417,632
499,488
30,545
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
$0.130
$0.130
$0.065
$0.089
$0.089
$0.119
$0.150
$0.190
$0.155
$0.101
$0.111
$0.150
$0.087
$0.120
$0.067
$0.102
$0.126
$0.175
$0.081
$0.115
$0.106
$0.135
$0.184
—
(19,073)
—
—
—
—
(50,700)
—
—
—
—
—
—
—
(639)
—
—
(10,306)
—
(188,722)
(517,575)
(11,111)
(6,666)
—
—
—
—
—
—
—
(37,689)
(523,625)
(11,958)
(20,528)
—
(125,875)
(29,057)
—
(135,920)
(6,562)
—
(4,400,423)
—
—
—
—
3,692,054
1,198
9,417,632
499,488
30,545
1,837,109
—
311,019
6,480,842
756,584
28,793
2,566
5,176,154
292,883
—
—
—
—
—
12,500
—
—
—
Totals
20,975,806
13,659,990
(804,792)
(5,291,637)
28,539,367
No rights were granted to key management personnel during FY2022. The following factors and assumptions were used in determining the
fair value of share rights granted to key management personnel during FY2021:
Grant Date Expiry Date
24 Jul 20201
30 Jun 2025
11 Nov 20202 30 Jun 2025
Fair Value
Per Right
Exercise
Price
Price of Shares
at Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
$0.065
$0.130
Nil
Nil
$0.089
$0.130
72%
N/A
0.43%
N/A
—
—
1
LTIP Rights for the plan year commencing 1 July 2020.
2 Deferred share rights issued in lieu of cash under the short term incentive plan for the year commencing 1 July 2019.
(f)
Expenses arising from share-based payment transactions
Total expenses arising from share-based transactions recognised during the year were:
Share Rights issued to employees
2022
$
2021
$
1,524,197
1,862,072
88
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
89
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
33. FINANCIAL RISK MANAGEMENT
33. FINANCIAL RISK MANAGEMENT (CONTINUED)
The Consolidated Entity’s principal financial instruments are cash and short-term deposits. The Consolidated Entity also has other financial
assets and liabilities such as trade receivables, trade payables and borrowings, which arise directly from its operations. The Consolidated
Entity’s risk management objective with regard to financial instruments and other financial assets include gaining interest income and the
policy is to do so with a minimum of risk.
The Group manages its exposure to key financial risks primarily through supervision by the Audit and Financial Risk Committee. One of the
primary functions of this Committee is to assist the Board to fulfil its responsibility to exercise due care, diligence and skill with respect to
the oversight and integrity of the management of financial risks and internal controls.
(a) Credit Risk
The credit risk on financial assets of the Consolidated Entity which have been recognised in the balance sheet is generally the carrying
amount, net of any provision for expected credit losses. The Group applies the simplified approach to providing for expected credit losses
prescribed by AASB 9, which permits the use of the lifetime expected loss provision for all trade receivables. Under this method,
determination of the loss allowance provision and expected loss rate incorporates past experience and forward-looking information,
including the outlook for market demand, the current economic environment, and forward-looking interest rates. As the expected loss rate
at 30 June 2022 is nil (2021: nil), no loss allowance provision has been recorded at 30 June 2022 (2021: nil).
The Consolidated Entity trades only with recognised banks and large customers where the credit risk is considered minimal.
Customer credit risk is managed in accordance with the Group’s established policy, procedures and controls. Outstanding customer
receivables are regularly monitored and relate to the Groups’ customers for which there is no history of credit risk or overdue payments.
An impairment analysis is performed at each reporting date on an individual basis for the major customers.
The aging of the Consolidated Entity’s receivables at reporting date was:
Trade and other receivables
Current: 0-30 days
Gross
Expected Credit
Loss Provision
2022
$’000
2021
$’000
2022
$’000
2021
$’000
4,750
6,084
4,750
6,084
—
—
—
—
The trade receivables at 30 June 2022 relate predominantly to oil and gas sales which have all been received subsequent to year end.
A deferred receivable arising from the partial sale of interests in Producing Assets is recorded at fair value (refer Note 8(b)) which takes into
account credit risk.
Credit risk also arises in relation to financial guarantees given by the Parent Entity and other non-borrowing Group entities to certain
parties in respect of borrowings by other Group entities (refer Note 25(b)). Such guarantees are only provided in exceptional circumstances
and are subject to specific Board approval.
(b)
Liquidity Risk
Prudent liquidity risk management implies maintaining sufficient cash, marketable securities and funding facilities. Management monitors
rolling forecasts of the Group’s liquidity reserve (comprising the undrawn borrowing facilities below) and cash and cash equivalents
(Note 7) based on expected cash flows. This is carried out at the Group level in accordance with practice and limits set by the Board of
Directors. The Group’s objective when managing capital is to safeguard the ability to continue as a going concern to ultimately add value
for shareholders through the exploitation and production of hydrocarbon resources.
In addition, the Group’s liquidity management policy involves projecting cash flows, monitoring balance sheet liquidity ratios and
maintaining debt financing plans. In order to satisfy the capital requirements of the Group, the Company may issue new shares or other
The following are the contractual maturities of financial assets and liabilities:
≤ 6 Months
6–12 Months
1–5 Years
≥ 5 Years
Contractual
Cash Flow
Carrying
Amount
equity instruments.
2022 ($’000)
Financial Assets
Cash and cash equivalents
Trade and other receivables
Other financial assets
Financial Liabilities
Trade and other payables
Interest bearing liabilities
2021 ($’000)
Financial Assets
Cash and cash equivalents
Trade and other receivables
Other financial assets
Financial Liabilities
Trade and other payables
Interest bearing liabilities
21,647
25,252
—
46,899
(13,526)
(3,706)
37,159
6,084
—
43,243
(10,491)
(33,245)
(3,644)
(30,495)
(17,232)
(3,644)
(30,495)
(51,439)
(45,336)
≤ 6 Months
6–12 Months
1–5 Years
≥ 5 Years
Contractual
Cash Flow
Carrying
Amount
—
621
—
621
—
—
—
—
—
—
—
—
4,410
4,410
—
—
—
4,218
4,218
—
—
—
—
—
—
(68)
(68)
—
—
—
—
—
(123)
(123)
21,647
25,873
4,410
51,930
21,647
25,570
4,410
51,627
(13,526)
(37,913)
(13,526)
(31,810)
37,159
6,084
4,218
47,461
37,159
6,084
4,218
47,461
(10,491)
(70,860)
(10,491)
(68,318)
(5,221)
(32,271)
(43,736)
(5,221)
(32,271)
(81,351)
(78,809)
90 CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
91
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
33. FINANCIAL RISK MANAGEMENT
33. FINANCIAL RISK MANAGEMENT (CONTINUED)
The Consolidated Entity’s principal financial instruments are cash and short-term deposits. The Consolidated Entity also has other financial
assets and liabilities such as trade receivables, trade payables and borrowings, which arise directly from its operations. The Consolidated
Entity’s risk management objective with regard to financial instruments and other financial assets include gaining interest income and the
policy is to do so with a minimum of risk.
The Group manages its exposure to key financial risks primarily through supervision by the Audit and Financial Risk Committee. One of the
primary functions of this Committee is to assist the Board to fulfil its responsibility to exercise due care, diligence and skill with respect to
the oversight and integrity of the management of financial risks and internal controls.
(a) Credit Risk
The credit risk on financial assets of the Consolidated Entity which have been recognised in the balance sheet is generally the carrying
amount, net of any provision for expected credit losses. The Group applies the simplified approach to providing for expected credit losses
prescribed by AASB 9, which permits the use of the lifetime expected loss provision for all trade receivables. Under this method,
determination of the loss allowance provision and expected loss rate incorporates past experience and forward-looking information,
including the outlook for market demand, the current economic environment, and forward-looking interest rates. As the expected loss rate
at 30 June 2022 is nil (2021: nil), no loss allowance provision has been recorded at 30 June 2022 (2021: nil).
The Consolidated Entity trades only with recognised banks and large customers where the credit risk is considered minimal.
Customer credit risk is managed in accordance with the Group’s established policy, procedures and controls. Outstanding customer
receivables are regularly monitored and relate to the Groups’ customers for which there is no history of credit risk or overdue payments.
An impairment analysis is performed at each reporting date on an individual basis for the major customers.
The aging of the Consolidated Entity’s receivables at reporting date was:
Trade and other receivables
Current: 0-30 days
Gross
Expected Credit
Loss Provision
2022
$’000
2021
$’000
2022
$’000
2021
$’000
4,750
6,084
4,750
6,084
—
—
—
—
The trade receivables at 30 June 2022 relate predominantly to oil and gas sales which have all been received subsequent to year end.
A deferred receivable arising from the partial sale of interests in Producing Assets is recorded at fair value (refer Note 8(b)) which takes into
account credit risk.
Credit risk also arises in relation to financial guarantees given by the Parent Entity and other non-borrowing Group entities to certain
parties in respect of borrowings by other Group entities (refer Note 25(b)). Such guarantees are only provided in exceptional circumstances
and are subject to specific Board approval.
(b)
Liquidity Risk
Prudent liquidity risk management implies maintaining sufficient cash, marketable securities and funding facilities. Management monitors
rolling forecasts of the Group’s liquidity reserve (comprising the undrawn borrowing facilities below) and cash and cash equivalents
(Note 7) based on expected cash flows. This is carried out at the Group level in accordance with practice and limits set by the Board of
Directors. The Group’s objective when managing capital is to safeguard the ability to continue as a going concern to ultimately add value
for shareholders through the exploitation and production of hydrocarbon resources.
In addition, the Group’s liquidity management policy involves projecting cash flows, monitoring balance sheet liquidity ratios and
maintaining debt financing plans. In order to satisfy the capital requirements of the Group, the Company may issue new shares or other
equity instruments.
The following are the contractual maturities of financial assets and liabilities:
2022 ($’000)
Financial Assets
Cash and cash equivalents
Trade and other receivables
Other financial assets
Financial Liabilities
Trade and other payables
Interest bearing liabilities
2021 ($’000)
Financial Assets
Cash and cash equivalents
Trade and other receivables
Other financial assets
Financial Liabilities
Trade and other payables
Interest bearing liabilities
≤ 6 Months
6–12 Months
1–5 Years
≥ 5 Years
Contractual
Cash Flow
Carrying
Amount
21,647
25,252
—
46,899
(13,526)
(3,706)
—
621
—
621
—
—
—
4,410
4,410
—
(3,644)
(30,495)
(17,232)
(3,644)
(30,495)
—
—
—
—
—
(68)
(68)
21,647
25,873
4,410
51,930
21,647
25,570
4,410
51,627
(13,526)
(37,913)
(13,526)
(31,810)
(51,439)
(45,336)
≤ 6 Months
6–12 Months
1–5 Years
≥ 5 Years
Contractual
Cash Flow
Carrying
Amount
37,159
6,084
—
43,243
(10,491)
(33,245)
—
—
—
—
—
—
—
4,218
4,218
—
(5,221)
(32,271)
(43,736)
(5,221)
(32,271)
—
—
—
—
—
(123)
(123)
37,159
6,084
4,218
47,461
37,159
6,084
4,218
47,461
(10,491)
(70,860)
(10,491)
(68,318)
(81,351)
(78,809)
90 CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
91
Total Financial Assets
Financial Liabilities:
Trade and other payables
Interest bearing liabilities
Financial Assets:
0.9
Cash and cash equivalents
Trade and other receivables —
0.2
Other financial assets
—
7.3
—
5.6
—
(30,809)
—
(66,809)
—
(1,001)
—
(1,509)
(13,526)
—
(10,491)
—
(13,526)
(31,810)
(10,491)
(68,318)
0.3
—
0.0
21,647
—
—
37,159
—
—
21,647
37,159
—
—
785
785
—
—
908
908
—
4,750
3,625
—
6,084
3,310
21,647
4,750
4,410
37,159
6,084
4,218
8,375
9,394
30,807
47,461
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
33. FINANCIAL RISK MANAGEMENT (CONTINUED)
33. FINANCIAL RISK MANAGEMENT (CONTINUED)
(c)
Interest Rate Risk
The Consolidated Entity’s exposure to interest rate risk, which is the risk that a financial instrument’s value will fluctuate as a result of
changes in market interest rates and the effective weighted average interest rates on classes of financial assets and financial liabilities, is as
follows:
Weighted
Average
Effective
Interest Rate
Floating
Interest Rate
Fixed Interest
Non-Interest-
Bearing
Total
2022
%
2021
%
2022
$’000
2021
$’000
2022
$’000
2021
$’000
2022
$’000
2021
$’000
2022
$’000
2021
$’000
(e)
Financing Facilities
The Group has a loan facility agreement (Facility) with Macquarie Bank Limited (Macquarie).
Interest costs are based on fixed spreads over the periodic Bank Bill Swap (BBSW) average bid rate. The Facility is structured as a partially
amortising term loan and has a maturity date of 30 September 2025 (2021: 30 September 2022). Repayments comprise fixed quarterly
principal repayments of $1,125,000 along with accrued interest. The Group does not have any interest rate hedging arrangements in place.
Under the terms of the Facility, the Group is required to comply with the following two key financial covenants:
1.
The Group Current Ratio is at least 1:1, excluding amounts payable under the Macquarie debt facility and certain liabilities associated
with gas sales agreements with Macquarie Bank.
2.
The Net Present Value with a 10% discount rate (NPV10) of forecasted net cash flow from the Palm Valley, Dingo and Mereenie gas
fields limited by the sales of only Proved Developed Producing reserves, divided by the outstanding loan amount must be greater
The Group remains compliant with these and all other financial covenants under the Facility.
than 1.3:1.
(f)
Currency Risk
The Consolidated Entity’s exposure to currency risk is limited due to its ongoing operations being in Australia and most associated contracts
completed in Australian dollars. A foreign exchange risk arises from oil sales denominated in US dollars and from liabilities denominated in
a currency other than Australian dollars. The Group generally does not undertake any hedging or forward contract transactions as the
exposure is considered immaterial, however, individual transactions are reviewed for any potential currency risk exposure.
At reporting date, the Group had the following exposure to foreign currency risk for balances denominated in foreign currencies from its
continuing operations, which are disclosed in Australian dollars:
Trade and other receivables (USD)
Trade and other payables:
-
-
-
USD
GBP
EUR
The following table details the Group’s Profit or Loss sensitivity to a 10% increase or decrease in the Australian dollar against the foreign
currency, with all other variables held constant. The sensitivity analysis is based on the foreign currency risk exposure at the reporting date.
Australian dollar +10% movement in exchange rate
Australian dollar -10% movement in exchange rate
These movements would not have any impact on equity other than retained earnings.
(g) Fair Values
2022
$’000
457
(1,082)
—
—
2022
$’000
57
(69)
2021
$’000
1,609
(416)
(3)
(3)
2021
$’000
(108)
132
Total Financial Liabilities
(30,809)
(66,809)
(1,001)
(1,509)
(13,526)
(10,491)
(45,336)
(78,809)
Net Financial Assets /
(Liabilities)
Interest Rate Sensitivity
(9,162)
(29,650)
(216)
(601)
(5,151)
(1,097)
(14,529)
(31,348)
A sensitivity of 50 basis points (0.5% pa) has been selected as this is considered a reasonable, scalable benchmark given the current level
and volatility of both short term and long term interest rates. A movement in interest rates of 0.5% pa at the reporting date would have
increased/(decreased) equity and profit and loss by the amounts shown below based on the average balance of interest-bearing financial
instruments held. This analysis assumes that all other variables remain constant.
The analysis is performed only on those financial assets and liabilities with floating interest rates and comparatives for 2021 have been
restated on the same basis.
Profit or Loss
Equity
50 basis points
increase in interest
rates
50 basis points
decrease in interest
rates
50 basis points
increase in interest
rates
50 basis points
decrease in interest
rates
2022 ($’000)
Cash and cash equivalents
Interest bearing liabilities
2021 ($’000)
Cash and cash equivalents
Interest bearing liabilities
102
(154)
186
(334)
(102)
154
(127)
334
—
—
—
—
—
—
—
—
These movements would not have any impact on equity other than retained earnings.
The carrying amounts of cash, cash equivalents, financial assets and financial liabilities, approximate their fair values.
(d) Commodity Risk
The majority of gas sales are made under long term contracts and as such do not contain any commodity risk for the duration of the
contract. The Consolidated Entity is exposed to commodity price fluctuations in respect of recorded crude oil sales and gas sales which are
not subject to long term fixed price contracts. The effect of potential fluctuations is not considered material to balances recorded in these
financial statements. The Board’s current policy is not to hedge crude oil sales. The Board will continue to monitor commodity price risk
and take action to mitigate that risk if it is considered necessary in light of the Group’s overall product sales mix and forecast cash flows.
92
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
93
(c)
Interest Rate Risk
follows:
changes in market interest rates and the effective weighted average interest rates on classes of financial assets and financial liabilities, is as
Weighted
Average
Effective
Interest Rate
Floating
Interest Rate
Fixed Interest
Non-Interest-
Bearing
Total
2022
%
2021
%
2022
$’000
2021
$’000
2022
$’000
2021
$’000
2022
$’000
2021
$’000
2022
$’000
2021
$’000
Financial Assets:
Cash and cash equivalents
0.9
21,647
37,159
Trade and other receivables —
Other financial assets
0.2
—
—
—
—
—
—
785
785
—
—
908
908
—
4,750
3,625
—
21,647
37,159
6,084
3,310
4,750
4,410
6,084
4,218
Trade and other payables
Interest bearing liabilities
—
7.3
—
—
—
—
(13,526)
(10,491)
(13,526)
(10,491)
(30,809)
(66,809)
(1,001)
(1,509)
—
—
(31,810)
(68,318)
Total Financial Liabilities
(30,809)
(66,809)
(1,001)
(1,509)
(13,526)
(10,491)
(45,336)
(78,809)
0.3
—
0.0
—
5.6
(9,162)
(29,650)
(216)
(601)
(5,151)
(1,097)
(14,529)
(31,348)
Total Financial Assets
Financial Liabilities:
Net Financial Assets /
(Liabilities)
Interest Rate Sensitivity
A sensitivity of 50 basis points (0.5% pa) has been selected as this is considered a reasonable, scalable benchmark given the current level
and volatility of both short term and long term interest rates. A movement in interest rates of 0.5% pa at the reporting date would have
increased/(decreased) equity and profit and loss by the amounts shown below based on the average balance of interest-bearing financial
instruments held. This analysis assumes that all other variables remain constant.
The analysis is performed only on those financial assets and liabilities with floating interest rates and comparatives for 2021 have been
restated on the same basis.
Profit or Loss
Equity
50 basis points
50 basis points
50 basis points
50 basis points
increase in interest
decrease in interest
increase in interest
decrease in interest
rates
rates
rates
rates
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
33. FINANCIAL RISK MANAGEMENT (CONTINUED)
33. FINANCIAL RISK MANAGEMENT (CONTINUED)
The Consolidated Entity’s exposure to interest rate risk, which is the risk that a financial instrument’s value will fluctuate as a result of
The Group has a loan facility agreement (Facility) with Macquarie Bank Limited (Macquarie).
(e)
Financing Facilities
Interest costs are based on fixed spreads over the periodic Bank Bill Swap (BBSW) average bid rate. The Facility is structured as a partially
amortising term loan and has a maturity date of 30 September 2025 (2021: 30 September 2022). Repayments comprise fixed quarterly
principal repayments of $1,125,000 along with accrued interest. The Group does not have any interest rate hedging arrangements in place.
Under the terms of the Facility, the Group is required to comply with the following two key financial covenants:
1.
2.
The Group Current Ratio is at least 1:1, excluding amounts payable under the Macquarie debt facility and certain liabilities associated
with gas sales agreements with Macquarie Bank.
The Net Present Value with a 10% discount rate (NPV10) of forecasted net cash flow from the Palm Valley, Dingo and Mereenie gas
fields limited by the sales of only Proved Developed Producing reserves, divided by the outstanding loan amount must be greater
than 1.3:1.
21,647
37,159
8,375
9,394
30,807
47,461
The Group remains compliant with these and all other financial covenants under the Facility.
(f)
Currency Risk
The Consolidated Entity’s exposure to currency risk is limited due to its ongoing operations being in Australia and most associated contracts
completed in Australian dollars. A foreign exchange risk arises from oil sales denominated in US dollars and from liabilities denominated in
a currency other than Australian dollars. The Group generally does not undertake any hedging or forward contract transactions as the
exposure is considered immaterial, however, individual transactions are reviewed for any potential currency risk exposure.
At reporting date, the Group had the following exposure to foreign currency risk for balances denominated in foreign currencies from its
continuing operations, which are disclosed in Australian dollars:
Trade and other receivables (USD)
Trade and other payables:
-
-
-
USD
GBP
EUR
2022
$’000
457
(1,082)
—
—
2021
$’000
1,609
(416)
(3)
(3)
102
(154)
186
(334)
(102)
154
(127)
334
—
—
—
—
—
—
—
—
Australian dollar +10% movement in exchange rate
Australian dollar -10% movement in exchange rate
These movements would not have any impact on equity other than retained earnings.
(g) Fair Values
2022
$’000
57
(69)
2021
$’000
(108)
132
The following table details the Group’s Profit or Loss sensitivity to a 10% increase or decrease in the Australian dollar against the foreign
currency, with all other variables held constant. The sensitivity analysis is based on the foreign currency risk exposure at the reporting date.
These movements would not have any impact on equity other than retained earnings.
The carrying amounts of cash, cash equivalents, financial assets and financial liabilities, approximate their fair values.
2022 ($’000)
Cash and cash equivalents
Interest bearing liabilities
2021 ($’000)
Cash and cash equivalents
Interest bearing liabilities
(d) Commodity Risk
The majority of gas sales are made under long term contracts and as such do not contain any commodity risk for the duration of the
contract. The Consolidated Entity is exposed to commodity price fluctuations in respect of recorded crude oil sales and gas sales which are
not subject to long term fixed price contracts. The effect of potential fluctuations is not considered material to balances recorded in these
financial statements. The Board’s current policy is not to hedge crude oil sales. The Board will continue to monitor commodity price risk
and take action to mitigate that risk if it is considered necessary in light of the Group’s overall product sales mix and forecast cash flows.
92
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2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
93
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
34.
INTERESTS IN JOINT ARRANGEMENTS
Details of joint arrangements in which the Consolidated Entity has an interest are as follows:
OL4, OL5 and PL2 - Mereenie
Oil & gas production
Principal Activities
OL3 - Palm Valley
L7 and PL30 - Dingo
EP 821
EP 105
EP 1122
EP 1253
EPA 111
EPA 124
Gas production
Gas production
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration – application
Oil & gas exploration – application
ATP 2031 - Range Gas Project
Oil & gas exploration
1 Central’s interest in EP82 will reduce to 29% upon satisfaction of conditions precedent to a farm-out agreement
2 Central’s interest in EP112 will reduce to 35% upon satisfaction of conditions precedent to a farm-out agreement
3 Central’s interest in EP125 will reduce to 24% upon satisfaction of conditions precedent to a farm-out agreement
2022
%
25.00
50.00
50.00
60.00
60.00
45.00
30.00
50.00
50.00
50.00
2021
%
50.00
N/a
N/a
60.00
60.00
30.00
30.00
50.00
50.00
50.00
The Joint Arrangements are accounted for based on contributions made to the Joint Operated Arrangements on an accruals basis. The
principal place of business is Australia.
Other parties’ rights to earn and retain participating interests in certain permits is subject to satisfying various obligations in their
respective farmout agreements. The participating interests as stated above assume such obligations have been met, or otherwise may be
subject to change or negotiation.
34.
INTERESTS IN JOINT ARRANGEMENTS (CONTINUED)
The share in the assets and liabilities of the joint arrangements where less than 100% interest is held by the Company are included in the
Consolidated Entity’s balance sheet in accordance with the accounting policy described in Note 1(b)(ii) under the following classifications:
Current assets
Cash and cash equivalents
Trade and other receivables
Inventory
Assets classified as held for sale
Total current assets
Non-current assets
Property, plant and equipment
Right of use assets
Other financial assets
Total non-current assets
Current liabilities
Trade and other payables
Lease liabilities
Deferred revenue
Provision for production over-lift
Restoration provision
Total current liabilities
Non-current liabilities
Deferred revenue
Lease liabilities
Provision for production over-lift
Restoration provision
Total non-current liabilities
Net assets
Revenue
Other income
Expenses
Profit before income tax
Joint arrangement contribution to loss before tax
Liabilities directly associated with assets classified as held for sale
2022
$’000
1,070
3,063
3,300
—
7,433
44,086
113
2,432
46,631
7,996
28
1,357
770
1,445
—
11,596
11,857
96
2,182
18,165
32,300
10,168
2021
$’000
878
4,424
722
29,227
35,251
28,264
87
1,328
29,679
3,382
25
365
734
—
13,370
17,876
219
70
2,830
12,800
15,919
31,135
35,973
7
(37,301)
35,248
12
(30,172)
(1,321)
5,088
35. EVENTS OCCURRING AFTER THE REPORTING PERIOD
No matters or circumstances have arisen between 30 June 2022 and the date of this report that will affect the Group’s operations, result or
state of affairs, or may do so in future years.
94
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
95
34.
INTERESTS IN JOINT ARRANGEMENTS
Details of joint arrangements in which the Consolidated Entity has an interest are as follows:
OL4, OL5 and PL2 - Mereenie
Oil & gas production
OL3 - Palm Valley
L7 and PL30 - Dingo
EP 821
EP 105
EP 1122
EP 1253
EPA 111
EPA 124
Principal Activities
Gas production
Gas production
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration – application
Oil & gas exploration – application
2022
%
25.00
50.00
50.00
60.00
60.00
45.00
30.00
50.00
50.00
50.00
2021
%
50.00
N/a
N/a
60.00
60.00
30.00
30.00
50.00
50.00
50.00
ATP 2031 - Range Gas Project
Oil & gas exploration
1 Central’s interest in EP82 will reduce to 29% upon satisfaction of conditions precedent to a farm-out agreement
2 Central’s interest in EP112 will reduce to 35% upon satisfaction of conditions precedent to a farm-out agreement
3 Central’s interest in EP125 will reduce to 24% upon satisfaction of conditions precedent to a farm-out agreement
The Joint Arrangements are accounted for based on contributions made to the Joint Operated Arrangements on an accruals basis. The
principal place of business is Australia.
Other parties’ rights to earn and retain participating interests in certain permits is subject to satisfying various obligations in their
respective farmout agreements. The participating interests as stated above assume such obligations have been met, or otherwise may be
subject to change or negotiation.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2022
34.
INTERESTS IN JOINT ARRANGEMENTS (CONTINUED)
The share in the assets and liabilities of the joint arrangements where less than 100% interest is held by the Company are included in the
Consolidated Entity’s balance sheet in accordance with the accounting policy described in Note 1(b)(ii) under the following classifications:
Current assets
Cash and cash equivalents
Trade and other receivables
Inventory
Assets classified as held for sale
Total current assets
Non-current assets
Property, plant and equipment
Right of use assets
Other financial assets
Total non-current assets
Current liabilities
Trade and other payables
Lease liabilities
Deferred revenue
Provision for production over-lift
Restoration provision
Liabilities directly associated with assets classified as held for sale
Total current liabilities
Non-current liabilities
Deferred revenue
Lease liabilities
Provision for production over-lift
Restoration provision
Total non-current liabilities
Net assets
Joint arrangement contribution to loss before tax
Revenue
Other income
Expenses
Profit before income tax
2022
$’000
1,070
3,063
3,300
—
7,433
44,086
113
2,432
46,631
7,996
28
1,357
770
1,445
—
11,596
11,857
96
2,182
18,165
32,300
10,168
2021
$’000
878
4,424
722
29,227
35,251
28,264
87
1,328
29,679
3,382
25
365
734
—
13,370
17,876
219
70
2,830
12,800
15,919
31,135
35,973
7
(37,301)
35,248
12
(30,172)
(1,321)
5,088
35. EVENTS OCCURRING AFTER THE REPORTING PERIOD
No matters or circumstances have arisen between 30 June 2022 and the date of this report that will affect the Group’s operations, result or
state of affairs, or may do so in future years.
94
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2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
95
DIRECTORS’ DECLARATION
INDEPENDENT AUDITOR’S REPORT
1.
In the Directors’ opinion:
a)
the financial statements and notes set out on pages 51 to 95 of the Consolidated Entity are in accordance with the
Corporations Act 2001 (Cth), including:
(i) complying with Accounting Standards, the Corporations Regulations 2001 (Cth) and other mandatory professional
reporting requirements, and
(ii) giving a true and fair view of the Consolidated Entity’s financial position as at 30 June 2022 and of its performance
for the financial year ended on that date;
b)
there are reasonable grounds to believe that the Company will be able to pay its debts as and when they become due and
payable; and
c) the financial statements comply with the International Financial Reporting Standards as issued by the International
Accounting Standards Board as disclosed in Note 1(a).
2. This declaration has been made after receiving the declarations required to be made to the Directors in accordance with section
295A of the Corporations Act 2001 (Cth) for the financial year ended 30 June 2022.
3. As at the date of this declaration, there are reasonable grounds to believe that the members of the Closed Group identified in
Note 27 will be able to meet any obligations or liabilities to which they are or may become subject by virtue of the Deed of Cross
Guarantee between the Company and those members of the Closed Group pursuant to ASIC Corporations (Wholly owned
Companies) Instrument 2016/785.
This declaration is made in accordance with a resolution of the Directors of Central Petroleum Limited:
Michael McCormack
Director
Brisbane
16 September 2022
Independent auditor’s report
To the members of Central Petroleum Limited
Report on the audit of the financial report
Our opinion
In our opinion:
•
•
•
•
•
•
explanatory information
the directors’ declaration.
Basis for opinion
our report.
opinion.
Independence
The accompanying financial report of Central Petroleum Limited (the Company) and its controlled entities
(together the Group) is in accordance with the Corporations Act 2001, including:
(a) giving a true and fair view of the Group's financial position as at 30 June 2022 and of its financial
performance for the year then ended
(b) complying with Australian Accounting Standards and the Corporations Regulations 2001.
What we have audited
The Group financial report comprises:
the consolidated balance sheet as at 30 June 2022
the consolidated statement of comprehensive income for the year then ended
the consolidated statement of changes in equity for the year then ended
the consolidated statement of cash flows for the year then ended
the notes to the consolidated financial statements, which include significant accounting policies and other
We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under those
standards are further described in the Auditor’s responsibilities for the audit of the financial report section of
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our
We are independent of the Group in accordance with the auditor independence requirements of the
Corporations Act 2001 and the ethical requirements of the Accounting Professional & Ethical Standards
Board’s APES 110 Code of Ethics for Professional Accountants (including Independence Standards) (the
Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled our other ethical
responsibilities in accordance with the Code.
PricewaterhouseCoopers, ABN 52 780 433 757
480 Queen Street, BRISBANE QLD 4000, GPO Box 150, BRISBANE QLD 4001
T: +61 7 3257 5000, F: +61 7 3257 5999
Liability limited by a scheme approved under Professional Standards Legislation
96
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97
FOR THE YEAR ENDED 30 JUNE 2022
DIRECTORS’ DECLARATION
1.
In the Directors’ opinion:
Corporations Act 2001 (Cth), including:
reporting requirements, and
a)
the financial statements and notes set out on pages 51 to 95 of the Consolidated Entity are in accordance with the
(i) complying with Accounting Standards, the Corporations Regulations 2001 (Cth) and other mandatory professional
(ii) giving a true and fair view of the Consolidated Entity’s financial position as at 30 June 2022 and of its performance
for the financial year ended on that date;
b)
there are reasonable grounds to believe that the Company will be able to pay its debts as and when they become due and
payable; and
c) the financial statements comply with the International Financial Reporting Standards as issued by the International
Accounting Standards Board as disclosed in Note 1(a).
295A of the Corporations Act 2001 (Cth) for the financial year ended 30 June 2022.
3. As at the date of this declaration, there are reasonable grounds to believe that the members of the Closed Group identified in
Note 27 will be able to meet any obligations or liabilities to which they are or may become subject by virtue of the Deed of Cross
Guarantee between the Company and those members of the Closed Group pursuant to ASIC Corporations (Wholly owned
Companies) Instrument 2016/785.
This declaration is made in accordance with a resolution of the Directors of Central Petroleum Limited:
Michael McCormack
Director
Brisbane
16 September 2022
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
INDEPENDENT AUDITOR’S REPORT
2. This declaration has been made after receiving the declarations required to be made to the Directors in accordance with section
performance for the year then ended
Independent auditor’s report
To the members of Central Petroleum Limited
Report on the audit of the financial report
Our opinion
In our opinion:
The accompanying financial report of Central Petroleum Limited (the Company) and its controlled entities
(together the Group) is in accordance with the Corporations Act 2001, including:
(a) giving a true and fair view of the Group's financial position as at 30 June 2022 and of its financial
(b) complying with Australian Accounting Standards and the Corporations Regulations 2001.
What we have audited
The Group financial report comprises:
•
•
•
•
•
•
the consolidated balance sheet as at 30 June 2022
the consolidated statement of comprehensive income for the year then ended
the consolidated statement of changes in equity for the year then ended
the consolidated statement of cash flows for the year then ended
the notes to the consolidated financial statements, which include significant accounting policies and other
explanatory information
the directors’ declaration.
Basis for opinion
We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under those
standards are further described in the Auditor’s responsibilities for the audit of the financial report section of
our report.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our
opinion.
Independence
We are independent of the Group in accordance with the auditor independence requirements of the
Corporations Act 2001 and the ethical requirements of the Accounting Professional & Ethical Standards
Board’s APES 110 Code of Ethics for Professional Accountants (including Independence Standards) (the
Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled our other ethical
responsibilities in accordance with the Code.
PricewaterhouseCoopers, ABN 52 780 433 757
480 Queen Street, BRISBANE QLD 4000, GPO Box 150, BRISBANE QLD 4001
T: +61 7 3257 5000, F: +61 7 3257 5999
Liability limited by a scheme approved under Professional Standards Legislation
96
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2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
97
INDEPENDENT AUDITOR’S REPORT
INDEPENDENT AUDITOR’S REPORT
Our audit approach
Key audit matters
An audit is designed to provide reasonable assurance about whether the financial report is free from material
misstatement. Misstatements may arise due to fraud or error. They are considered material if individually or
in aggregate, they could reasonably be expected to influence the economic decisions of users taken on the
basis of the financial report.
We tailored the scope of our audit to ensure that we performed enough work to be able to give an opinion on
the financial report as a whole, taking into account the geographic and management structure of the Group,
its accounting processes and controls and the industry in which it operates.
Materiality
Audit scope
•
For the purpose of our audit we used overall Group
materiality of $1.2 million, which represents
approximately 1% of the Group’s total assets.
• We applied this threshold, together with qualitative
• Our audit focused on where the Group made
subjective judgements; for example, significant
accounting estimates involving assumptions and
inherently uncertain future events.
considerations, to determine the scope of our audit and
the nature, timing and extent of our audit procedures and
to evaluate the effect of misstatements on the financial
report as a whole.
•
• We chose Group total assets because, in our view, it is
the benchmark against which the performance of the
Group is most commonly measured and is a generally
accepted benchmark in the oil and gas industry for
entities at a similar stage of development.
• We utilised a 1% threshold based on our
professional judgement, noting it is within the range
of commonly acceptable thresholds.
The Group produces oil and gas from its interests
in fields in the Northern Territory and continues to
conduct exploration and evaluation activities in
respect of tenements located in the Northern
Territory and Queensland.
Key audit matters are those matters that, in our professional judgement, were of most significance in our
audit of the financial report for the current period. The key audit matters were addressed in the context of our
audit of the financial report as a whole, and in forming our opinion thereon, and we do not provide a separate
opinion on these matters. Further, any commentary on the outcomes of a particular audit procedure is made
in that context. We communicated the key audit matters to the Audit and Financial Risk Committee.
Key audit matter
How our audit addressed the key audit matter
To evaluate the Group’s profit on disposal, we performed a
Profit on disposal of 50% interest in Amadeus Basin
number of procedures including the following:
producing properties (Refer to note 3)
● Read the terms of the Sale Agreement.
On 1 October 2021, the Group completed the sale of 50%
● Performed an evaluation over the date at which
of its working interest in the Amadeus Basin producing
control was lost.
assets to entities controlled by New Zealand Oil and Gas
● Agreed net cash received from NZOG and Cue
Limited ("NZOG") and Cue Energy Resources Limited
on completion to underlying bank statements.
("Cue"). An accounting profit of $36.6m was recorded as a
● Evaluated management’s key fair value
result of this transaction.
The disposal was a key audit matter because of the
transaction being non-routine and its financial significance
to the financial statements.
assumptions related to valuation of deferred
consideration.
● Recalculated the gain on sale by comparing the
carrying value of the disposed assets and
liabilities to consideration received, less
transaction costs.
● Evaluated the reasonableness of the
disclosures made in note 3, in light of the
requirements of the Australian Accounting
Standards.
Other information
our auditor’s report thereon.
The directors are responsible for the other information. The other information comprises the information
included in the annual report for the year ended 30 June 2022, but does not include the financial report and
Our opinion on the financial report does not cover the other information and accordingly we do not express any
form of assurance conclusion thereon.
In connection with our audit of the financial report, our responsibility is to read the other information and, in
doing so, consider whether the other information is materially inconsistent with the financial report or our
knowledge obtained in the audit, or otherwise appears to be materially misstated.
If, based on the work we have performed on the other information that we obtained prior to the date of this
auditor’s report, we conclude that there is a material misstatement of this other information, we are required to
report that fact. We have nothing to report in this regard.
98
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2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 99
INDEPENDENT AUDITOR’S REPORT
INDEPENDENT AUDITOR’S REPORT
Our audit approach
Key audit matters
An audit is designed to provide reasonable assurance about whether the financial report is free from material
misstatement. Misstatements may arise due to fraud or error. They are considered material if individually or
in aggregate, they could reasonably be expected to influence the economic decisions of users taken on the
basis of the financial report.
We tailored the scope of our audit to ensure that we performed enough work to be able to give an opinion on
the financial report as a whole, taking into account the geographic and management structure of the Group,
its accounting processes and controls and the industry in which it operates.
Materiality
Audit scope
•
For the purpose of our audit we used overall Group
• Our audit focused on where the Group made
materiality of $1.2 million, which represents
approximately 1% of the Group’s total assets.
• We applied this threshold, together with qualitative
considerations, to determine the scope of our audit and
the nature, timing and extent of our audit procedures and
to evaluate the effect of misstatements on the financial
•
report as a whole.
• We chose Group total assets because, in our view, it is
the benchmark against which the performance of the
Group is most commonly measured and is a generally
accepted benchmark in the oil and gas industry for
entities at a similar stage of development.
• We utilised a 1% threshold based on our
professional judgement, noting it is within the range
of commonly acceptable thresholds.
subjective judgements; for example, significant
accounting estimates involving assumptions and
inherently uncertain future events.
The Group produces oil and gas from its interests
in fields in the Northern Territory and continues to
conduct exploration and evaluation activities in
respect of tenements located in the Northern
Territory and Queensland.
Key audit matters are those matters that, in our professional judgement, were of most significance in our
audit of the financial report for the current period. The key audit matters were addressed in the context of our
audit of the financial report as a whole, and in forming our opinion thereon, and we do not provide a separate
opinion on these matters. Further, any commentary on the outcomes of a particular audit procedure is made
in that context. We communicated the key audit matters to the Audit and Financial Risk Committee.
Key audit matter
How our audit addressed the key audit matter
Profit on disposal of 50% interest in Amadeus Basin
producing properties (Refer to note 3)
On 1 October 2021, the Group completed the sale of 50%
of its working interest in the Amadeus Basin producing
assets to entities controlled by New Zealand Oil and Gas
Limited ("NZOG") and Cue Energy Resources Limited
("Cue"). An accounting profit of $36.6m was recorded as a
result of this transaction.
The disposal was a key audit matter because of the
transaction being non-routine and its financial significance
to the financial statements.
To evaluate the Group’s profit on disposal, we performed a
number of procedures including the following:
● Read the terms of the Sale Agreement.
● Performed an evaluation over the date at which
control was lost.
● Agreed net cash received from NZOG and Cue
on completion to underlying bank statements.
● Evaluated management’s key fair value
assumptions related to valuation of deferred
consideration.
● Recalculated the gain on sale by comparing the
carrying value of the disposed assets and
liabilities to consideration received, less
transaction costs.
● Evaluated the reasonableness of the
disclosures made in note 3, in light of the
requirements of the Australian Accounting
Standards.
Other information
The directors are responsible for the other information. The other information comprises the information
included in the annual report for the year ended 30 June 2022, but does not include the financial report and
our auditor’s report thereon.
Our opinion on the financial report does not cover the other information and accordingly we do not express any
form of assurance conclusion thereon.
In connection with our audit of the financial report, our responsibility is to read the other information and, in
doing so, consider whether the other information is materially inconsistent with the financial report or our
knowledge obtained in the audit, or otherwise appears to be materially misstated.
If, based on the work we have performed on the other information that we obtained prior to the date of this
auditor’s report, we conclude that there is a material misstatement of this other information, we are required to
report that fact. We have nothing to report in this regard.
98
CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 99
INDEPENDENT AUDITOR’S REPORT
INDEPENDENT AUDITOR’S REPORT
The directors of the Company are responsible for the preparation and presentation of the remuneration report in
accordance with section 300A of the Corporations Act 2001. Our responsibility is to express an opinion on the
remuneration report, based on our audit conducted in accordance with Australian Auditing Standards.
PricewaterhouseCoopers
Marcus Goddard
Partner
Brisbane
16 September 2022
Responsibilities of the directors for the financial report
Responsibilities
The directors of the Company are responsible for the preparation of the financial report that gives a true and
fair view in accordance with Australian Accounting Standards and the Corporations Act 2001 and for such
internal control as the directors determine is necessary to enable the preparation of the financial report that
gives a true and fair view and is free from material misstatement, whether due to fraud or error.
In preparing the financial report, the directors are responsible for assessing the ability of the Group to
continue as a going concern, disclosing, as applicable, matters related to going concern and using the going
concern basis of accounting unless the directors either intend to liquidate the Group or to cease operations,
or have no realistic alternative but to do so.
Auditor’s responsibilities for the audit of the financial report
Our objectives are to obtain reasonable assurance about whether the financial report as a whole is free from
material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion.
Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in
accordance with the Australian Auditing Standards will always detect a material misstatement when it exists.
Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they
could reasonably be expected to influence the economic decisions of users taken on the basis of the financial
report.
A further description of our responsibilities for the audit of the financial report is located at the Auditing and
Assurance Standards Board website at: https://www.auasb.gov.au/admin/file/content102/c3/ar1_2020.pdf. This
description forms part of our auditor's report.
Report on the remuneration report
Our opinion on the remuneration report
We have audited the remuneration report included in pages 34 to 48 of the directors’ report for the year ended
30 June 2022.
In our opinion, the remuneration report of Central Petroleum Limited for the year ended 30 June 2022 complies
with section 300A of the Corporations Act 2001.
100 CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
101
INDEPENDENT AUDITOR’S REPORT
INDEPENDENT AUDITOR’S REPORT
Responsibilities of the directors for the financial report
Responsibilities
The directors of the Company are responsible for the preparation and presentation of the remuneration report in
accordance with section 300A of the Corporations Act 2001. Our responsibility is to express an opinion on the
remuneration report, based on our audit conducted in accordance with Australian Auditing Standards.
PricewaterhouseCoopers
Marcus Goddard
Partner
Brisbane
16 September 2022
The directors of the Company are responsible for the preparation of the financial report that gives a true and
fair view in accordance with Australian Accounting Standards and the Corporations Act 2001 and for such
internal control as the directors determine is necessary to enable the preparation of the financial report that
gives a true and fair view and is free from material misstatement, whether due to fraud or error.
In preparing the financial report, the directors are responsible for assessing the ability of the Group to
continue as a going concern, disclosing, as applicable, matters related to going concern and using the going
concern basis of accounting unless the directors either intend to liquidate the Group or to cease operations,
or have no realistic alternative but to do so.
Auditor’s responsibilities for the audit of the financial report
Our objectives are to obtain reasonable assurance about whether the financial report as a whole is free from
material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion.
Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in
accordance with the Australian Auditing Standards will always detect a material misstatement when it exists.
Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they
could reasonably be expected to influence the economic decisions of users taken on the basis of the financial
report.
A further description of our responsibilities for the audit of the financial report is located at the Auditing and
Assurance Standards Board website at: https://www.auasb.gov.au/admin/file/content102/c3/ar1_2020.pdf. This
description forms part of our auditor's report.
Report on the remuneration report
Our opinion on the remuneration report
We have audited the remuneration report included in pages 34 to 48 of the directors’ report for the year ended
30 June 2022.
In our opinion, the remuneration report of Central Petroleum Limited for the year ended 30 June 2022 complies
with section 300A of the Corporations Act 2001.
100 CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
101
ASX ADDITIONAL INFORMATION
ASX ADDITIONAL INFORMATION
DETAILS OF QUOTED SECURITIES AS AT 13 SEPTEMBER 2022
SUBSTANTIAL SHAREHOLDERS
Top holders
The 20 largest registered holders of the quoted securities as at 13 September 2022 were:
Substantial shareholders as disclosed by notices received by the Company as at 13 September 2022 with holdings of 5% or more of the
total votes attached to the voting shares or interests in the Entity:
Name
Norfolk Enchants Pty Ltd
UBS Nominees Pty Ltd
Mrs Faina Stolyar
Moranbah Nominees Pty Ltd
Brazil Farming Pty Ltd
Citicorp Nominees Pty Limited
Macquarie Bank Limited
Mr Philip Gasteen
Chembank Pty Limited
Kensington Capital Partners Pty Ltd
JH Nominees Australia Pty Ltd
1
2
3
4
5
6
7
8
9
10
11
12-13 Justwright Investments Pty Ltd
12-13 PA and RE Gibson Pty Ltd
14
15
Mr Donald Leonard Cottee
Mr James Donald Bruce Cochrane + Mrs Joan Elizabeth Cochrane
16-19 Mr Chris Carr + Mrs Betsy Carr
16-19 Garmi Holdings Pty Ltd
16-19 Garmi Holdings Pty Ltd
16-19 Mr Peter Andrew Gibson + Mrs Robyn Elizabeth Gibson
20
Mrs Karen Driscoll + Mr Raymond Driscoll
No. of
Shares
37,500,000
29,957,170
20,000,000
19,526,612
17,785,209
16,784,101
14,166,667
11,945,080
10,000,000
8,000,000
7,840,268
7,000,000
7,000,000
5,830,594
5,000,001
5,000,000
5,000,000
5,000,000
5,000,000
4,915,250
%
5.17
4.13
2.76
2.69
2.45
2.31
1.95
1.65
1.38
1.10
1.08
0.96
0.96
0.80
0.69
0.69
0.69
0.69
0.69
0.68
Total 243,250,952 33.51
DISTRIBUTION SCHEDULE
A distribution schedule of the number of holders in each class of equity securities as at 13 September 2022 was:
Size of Holding
1 – 1,000
1,001 – 5,000
5,001 – 10,000
10,001 – 100,000
100,001 – Over
Total
Number of Holders
Listed Fully
Paid Shares
Unlisted
Share Rights
Unlisted
Options
742
1,736
953
2,407
899
6,737
1
3
12
48
25
89
—
—
—
—
5
5
Holdings less than a marketable parcel of ordinary shares (being 5,883 shares as at 13 September 2022):
Holder
Troy Harry
Units
55,000,000
UNMARKETABLE PARCELS
Holders
2,596
Units
5,813,238
VOTING RIGHTS
Subject to any rights or restrictions for the time being attached to any class or classes of shares, at meetings of shareholders or classes of
shareholders:
and
•
•
•
each shareholder entitled to vote may vote in person or by proxy, attorney or representative of a shareholder;
on a show of hands, every person present who is a shareholder or a proxy, attorney or representative of a shareholder has one vote;
on a poll, every person present who is a shareholder shall, in respect of each fully paid share held by him, or in respect of which he is
appointed a proxy, attorney or representative, have one vote for their share, but in respect of partly paid shares, shall have such
number of votes being equivalent to the proportion which the amount paid (not credited) is of the total amounts paid and payable in
respect of those shares (excluding amounts credited).
ON-MARKET BUY-BACK
There is no current on-market buy-back of the Company’s securities.
CORPORATE GOVERNANCE STATEMENT
Central Petroleum Limited and its Board are committed to achieving and demonstrating high standards of corporate governance. The
Company has reviewed its corporate governance practices against the Corporate Governance Principles and Recommendations (4th edition)
published by the ASX Corporate Governance Council.
The 2022 Corporate Governance Statement reflects the corporate governance practices in place throughout the 2022 financial year. The
Company’s Corporate Governance Statement undergoes periodic review by the Board. A description of the Group’s current corporate
governance practices is set out in the Group’s Corporate Governance Statement which can be viewed at
www.centralpetroleum.com.au/about/corporate-governance/.
102 CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
103
ASX ADDITIONAL INFORMATION
ASX ADDITIONAL INFORMATION
DETAILS OF QUOTED SECURITIES AS AT 13 SEPTEMBER 2022
SUBSTANTIAL SHAREHOLDERS
The 20 largest registered holders of the quoted securities as at 13 September 2022 were:
Top holders
Name
Norfolk Enchants Pty Ltd
UBS Nominees Pty Ltd
Mrs Faina Stolyar
Brazil Farming Pty Ltd
Citicorp Nominees Pty Limited
Moranbah Nominees Pty Ltd
Macquarie Bank Limited
Mr Philip Gasteen
Chembank Pty Limited
Kensington Capital Partners Pty Ltd
JH Nominees Australia Pty Ltd
12-13 Justwright Investments Pty Ltd
12-13 PA and RE Gibson Pty Ltd
Mr Donald Leonard Cottee
1
2
3
4
5
6
7
8
9
10
11
14
15
16-19 Mr Chris Carr + Mrs Betsy Carr
16-19 Garmi Holdings Pty Ltd
16-19 Garmi Holdings Pty Ltd
16-19 Mr Peter Andrew Gibson + Mrs Robyn Elizabeth Gibson
20
Mrs Karen Driscoll + Mr Raymond Driscoll
Mr James Donald Bruce Cochrane + Mrs Joan Elizabeth Cochrane
No. of
Shares
37,500,000
29,957,170
20,000,000
19,526,612
17,785,209
16,784,101
14,166,667
11,945,080
10,000,000
8,000,000
7,840,268
7,000,000
7,000,000
5,830,594
5,000,001
5,000,000
5,000,000
5,000,000
5,000,000
4,915,250
%
5.17
4.13
2.76
2.69
2.45
2.31
1.95
1.65
1.38
1.10
1.08
0.96
0.96
0.80
0.69
0.69
0.69
0.69
0.69
0.68
Total 243,250,952 33.51
DISTRIBUTION SCHEDULE
A distribution schedule of the number of holders in each class of equity securities as at 13 September 2022 was:
Number of Holders
Listed Fully
Paid Shares
Unlisted
Share Rights
Unlisted
Options
Size of Holding
1 – 1,000
1,001 – 5,000
5,001 – 10,000
10,001 – 100,000
100,001 – Over
Total
742
1,736
953
2,407
899
6,737
1
3
12
48
25
89
—
—
—
—
5
5
Substantial shareholders as disclosed by notices received by the Company as at 13 September 2022 with holdings of 5% or more of the
total votes attached to the voting shares or interests in the Entity:
Holder
Troy Harry
Units
55,000,000
UNMARKETABLE PARCELS
Holdings less than a marketable parcel of ordinary shares (being 5,883 shares as at 13 September 2022):
Holders
2,596
Units
5,813,238
VOTING RIGHTS
Subject to any rights or restrictions for the time being attached to any class or classes of shares, at meetings of shareholders or classes of
shareholders:
each shareholder entitled to vote may vote in person or by proxy, attorney or representative of a shareholder;
•
•
•
on a show of hands, every person present who is a shareholder or a proxy, attorney or representative of a shareholder has one vote;
and
on a poll, every person present who is a shareholder shall, in respect of each fully paid share held by him, or in respect of which he is
appointed a proxy, attorney or representative, have one vote for their share, but in respect of partly paid shares, shall have such
number of votes being equivalent to the proportion which the amount paid (not credited) is of the total amounts paid and payable in
respect of those shares (excluding amounts credited).
ON-MARKET BUY-BACK
There is no current on-market buy-back of the Company’s securities.
CORPORATE GOVERNANCE STATEMENT
Central Petroleum Limited and its Board are committed to achieving and demonstrating high standards of corporate governance. The
Company has reviewed its corporate governance practices against the Corporate Governance Principles and Recommendations (4th edition)
published by the ASX Corporate Governance Council.
The 2022 Corporate Governance Statement reflects the corporate governance practices in place throughout the 2022 financial year. The
Company’s Corporate Governance Statement undergoes periodic review by the Board. A description of the Group’s current corporate
governance practices is set out in the Group’s Corporate Governance Statement which can be viewed at
www.centralpetroleum.com.au/about/corporate-governance/.
102 CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
2022 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
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INTERESTS IN PETROLEUM PERMITS AND PIPELINE
LICENCES
AT THE DATE OF THIS REPORT
PERMITS AND LICENCES GRANTED
Tenement
Location
Operator
Registered
Interest (%)
Beneficial
Interest (%)
Participant Name
Beneficial
Interest (%)
CTP Consolidated Entity Other JV Participants
EP82 (excl. EP82 Sub-Blocks) 1(a) Amadeus Basin NT
EP82 Sub-Blocks
Amadeus Basin NT
Santos
Central
EP105
EP112 1(b) & 2
EP115 (excl. EP115 North
Mereenie Block)
Amadeus/Pedirka Basin NT
Santos
Amadeus Basin NT
Amadeus Basin NT
EP115 North Mereenie Block Amadeus Basin NT
EP1251(c)
OL3 (Palm Valley)
Amadeus Basin NT
Amadeus Basin NT
Santos
Central
Central
Santos
Central
60
100
60
30
100
100
30
50
OL4 (Mereenie)
Amadeus Basin NT
Central
25
60
100
60
45
100
100
30
50
25
OL5 (Mereenie)
Amadeus Basin NT
Central
25
25
L6 (Surprise)
L7 (Dingo)
RL3 (Ooraminna)
RL4 (Ooraminna)
ATP909
ATP911
ATP912
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Georgina Basin QLD
Georgina Basin QLD
Georgina Basin QLD
ATP2031 (Range Gas Project)
Surat Basin QLD
Central
Central
Central
Central
Central
Central
Central
Central
100
50
100
100
100
100
100
50
100
50
100
100
100
100
100
50
Santos QNT Pty Ltd (Santos)
Santos
Santos
Santos
NZOG Palm Valley Pty Ltd
Cue Palm Valley Pty Ltd
Macquarie Mereenie Pty Ltd
NZOG Mereenie Pty Ltd
Cue Mereenie Pty Ltd
Macquarie Mereenie Pty Ltd
NZOG Mereenie Pty Ltd
Cue Mereenie Pty Ltd
NZOG Dingo Pty Ltd
Cue Dingo Pty Ltd
40
40
55
70
35
15
50
17.5
7.5
50
17.5
7.5
35
15
Incitec Pivot Queensland Gas Pty
Ltd
50
INTERESTS IN PETROLEUM PERMITS AND PIPELINE
LICENCES
AT THE DATE OF THIS REPORT
PIPELINE LICENCES
Pipeline Licence
Location
Operator
CTP Consolidated Entity
Other JV Participants
Registered
Interest (%)
Beneficial
Interest (%) Participant Name
Beneficial
Interest (%)
Amadeus Basin NT
Central
25
25
Macquarie Mereenie Pty Ltd
Amadeus Basin NT
Central
50
50
NZOG Dingo Pty Ltd
NZOG Mereenie Pty Ltd
Cue Mereenie Pty Ltd
Cue Dingo Pty Ltd
50
17.5
7.5
35
15
1 As announced on 9 February 2022, Central entered into a farmout of various interest in certain Amadeus Basin exploration tenements to Peak Helium (Amadeus
Basin) Pty Ltd subject to the usual conditions precedent for a transaction of this nature being met by 12 October 2022. Upon completion, Peak Helium (Amadeus
Basin) Pty Ltd will earn partial transfer of Central’s interest in three permits as follows:
31% in EP82, excluding Dingo Satellite Area (Central’s interest will change from 60% to 29%)
10% in EP112 (Central’s interest will change from 45% to 35%); and
6% in EP125 (Central’s interest will change from 30% to 24%)
2 As announced on 2 August 2021, Santos did not elect that Central be carried for the first $3 million of Dukas-1 well costs and therefore its interest in EP112
(including Dukas-1 well) will decrease from 70% to 55% (Central’s interest in EP112 will increase from 30% to 45%)
3 On 16 December 2021 Central received notice from the NT Department of Industry Tourism and Trade that EPA111 had been placed in moratorium for a period of 5
years from 9 December 2021 until 9 December 2026.
4 On 22 March 2018 (in respect EPA124) and on 23 March 2018 (in respect of EPA152) Central received notice from the NT Department of Primary Industry and
Resources that EPA124 and EPA152, as applicable, had been placed in moratorium for a period of 5-years from 6 December 2017 until 6 December 2022.
5 This exploration permit application has been disposed. Transfer of the registered interest is awaiting the grant of an exploration permit.
6 This exploration permit application was placed into moratorium on 22 October 2015 for a five (5) year period ending on 22 October 2020. On 25 February 2021,
Central was provided with consent to negotiate the grant of this exploration permit.
PL2
PL30
Notes:
(a)
(b)
(c)
PERMITS AND LICENCES UNDER APPLICATION
Tenement
Location
Operator
Registered
Interest (%)
Beneficial
Interest (%) Participant Name
Beneficial
Interest (%)
CTP Consolidated Entity Other JV Participants
Santos
Santos
50
50
EPA92
EPA1113
EPA120
EPA124 4
EPA129
EPA130
EPA131 5
EPA132
EPA133 6
EPA137
EPA147
EPA149
EPA152 4
EPA160
EPA296
Wiso Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Wiso Basin NT
Pedirka Basin NT
Pedirka Basin NT
Georgina Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Wiso Basin NT
Wiso Basin NT
Central
Santos
Central
Santos
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
50
100
50
100
100
0
100
100
100
100
100
100
100
100
104 CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
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105
INTERESTS IN PETROLEUM PERMITS AND PIPELINE
LICENCES
AT THE DATE OF THIS REPORT
PIPELINE LICENCES
Pipeline Licence
Location
Operator
CTP Consolidated Entity
Other JV Participants
Registered
Interest (%)
Beneficial
Interest (%) Participant Name
Beneficial
Interest (%)
PL2
PL30
Amadeus Basin NT
Central
25
Amadeus Basin NT
Central
50
25
50
Macquarie Mereenie Pty Ltd
NZOG Mereenie Pty Ltd
Cue Mereenie Pty Ltd
NZOG Dingo Pty Ltd
Cue Dingo Pty Ltd
50
17.5
7.5
35
15
Notes:
1 As announced on 9 February 2022, Central entered into a farmout of various interest in certain Amadeus Basin exploration tenements to Peak Helium (Amadeus
Basin) Pty Ltd subject to the usual conditions precedent for a transaction of this nature being met by 12 October 2022. Upon completion, Peak Helium (Amadeus
Basin) Pty Ltd will earn partial transfer of Central’s interest in three permits as follows:
(a)
(b)
(c)
31% in EP82, excluding Dingo Satellite Area (Central’s interest will change from 60% to 29%)
10% in EP112 (Central’s interest will change from 45% to 35%); and
6% in EP125 (Central’s interest will change from 30% to 24%)
2 As announced on 2 August 2021, Santos did not elect that Central be carried for the first $3 million of Dukas-1 well costs and therefore its interest in EP112
(including Dukas-1 well) will decrease from 70% to 55% (Central’s interest in EP112 will increase from 30% to 45%)
3 On 16 December 2021 Central received notice from the NT Department of Industry Tourism and Trade that EPA111 had been placed in moratorium for a period of 5
years from 9 December 2021 until 9 December 2026.
4 On 22 March 2018 (in respect EPA124) and on 23 March 2018 (in respect of EPA152) Central received notice from the NT Department of Primary Industry and
Resources that EPA124 and EPA152, as applicable, had been placed in moratorium for a period of 5-years from 6 December 2017 until 6 December 2022.
5 This exploration permit application has been disposed. Transfer of the registered interest is awaiting the grant of an exploration permit.
6 This exploration permit application was placed into moratorium on 22 October 2015 for a five (5) year period ending on 22 October 2020. On 25 February 2021,
Central was provided with consent to negotiate the grant of this exploration permit.
INTERESTS IN PETROLEUM PERMITS AND PIPELINE
LICENCES
AT THE DATE OF THIS REPORT
PERMITS AND LICENCES GRANTED
CTP Consolidated Entity Other JV Participants
Operator
Registered
Interest (%)
Beneficial
Interest (%)
Participant Name
Beneficial
Interest (%)
Santos QNT Pty Ltd (Santos)
Amadeus/Pedirka Basin NT
Santos
Amadeus Basin NT
Santos
Santos
Tenement
Location
EP82 (excl. EP82 Sub-Blocks) 1(a) Amadeus Basin NT
EP82 Sub-Blocks
Amadeus Basin NT
EP105
EP112 1(b) & 2
Mereenie Block)
EP115 (excl. EP115 North
Amadeus Basin NT
EP115 North Mereenie Block Amadeus Basin NT
EP1251(c)
OL3 (Palm Valley)
Amadeus Basin NT
Amadeus Basin NT
OL4 (Mereenie)
Amadeus Basin NT
Central
25
25
Macquarie Mereenie Pty Ltd
OL5 (Mereenie)
Amadeus Basin NT
Central
25
25
Macquarie Mereenie Pty Ltd
40
40
55
70
35
15
50
17.5
7.5
50
17.5
7.5
35
15
50
50
Santos
NZOG Palm Valley Pty Ltd
Cue Palm Valley Pty Ltd
NZOG Mereenie Pty Ltd
Cue Mereenie Pty Ltd
NZOG Mereenie Pty Ltd
Cue Mereenie Pty Ltd
NZOG Dingo Pty Ltd
Cue Dingo Pty Ltd
Incitec Pivot Queensland Gas Pty
50
Ltd
Santos
Santos
Santos
Central
Santos
Central
Central
Santos
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Santos
Central
Santos
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
60
100
60
30
100
100
30
50
100
50
100
100
100
100
100
50
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
60
100
60
45
100
100
30
50
100
50
100
100
100
100
100
50
100
50
100
50
100
100
0
100
100
100
100
100
100
100
100
L6 (Surprise)
L7 (Dingo)
RL3 (Ooraminna)
RL4 (Ooraminna)
ATP909
ATP911
ATP912
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Georgina Basin QLD
Georgina Basin QLD
Georgina Basin QLD
ATP2031 (Range Gas Project)
Surat Basin QLD
EPA92
EPA1113
EPA120
EPA124 4
EPA129
EPA130
EPA131 5
EPA132
EPA133 6
EPA137
EPA147
EPA149
EPA152 4
EPA160
EPA296
Wiso Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Wiso Basin NT
Pedirka Basin NT
Pedirka Basin NT
Georgina Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Wiso Basin NT
Wiso Basin NT
PERMITS AND LICENCES UNDER APPLICATION
Tenement
Location
Operator
Registered
Interest (%)
Beneficial
Interest (%) Participant Name
Beneficial
Interest (%)
CTP Consolidated Entity Other JV Participants
104 CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
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105
GLOSSARY AND ABBREVIATIONS
CORPORATE DIRECTORY
1P
2C
2P
Bbl
Bopd
CSG
EBIT
Proved reserves*
Best estimate contingent resources*
Proved and probable reserves*
barrel of oil (unit of measure)
barrel of oil per day
coal seam gas
Earnings before interest and tax
EBITDA
Earnings before interest, tax, depreciation and amortisation
GROUP GENERAL COUNSEL AND COMPANY SECRETARY
EBITDAX
Earnings before interest, tax, depreciation, amortisation and exploration costs
Mr Daniel White LLB, BCom, LLM
EIP
ESOP
GJ
GJe
GSA
KMP
KPI
LTIP
Mcfd
mmbl
PJ
PJe
scfd
STIP
TFR
TJ
TJ/d
Tcf
Executive incentive plan
Executive share option plan
Gigajoule (1 billion joules) (unit of energy measure)
Gigajoule equivalent (oil converted at 5.816 GJe / bbl)
Gas sale agreement
Key management personnel
Key performance indicator
Long term incentive plan
Thousand cubic feet per day
Million barrels
Petajoules (1,000 TJ) (unit of energy measure)
Petajoule equivalent (oil converted at 5.816 PJe / mmbbl)
Standard cubic feet per day
Short term incentive plan
Total fixed remuneration
Terajoule (1,000 GJ) (unit of energy measure)
Terajoules per day
Trillion cubic feet (unit of measure)
* As defined by Petroleum Resources Management System (PRMS) 2018 published by the Society of Petroleum Engineers.
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS
Mr Michael (Mick) McCormack BSurv, GradDipEng, MBA, FAICD, Independent Non-Executive Director, Chair
Mr Leon Devaney BSc MBA, Managing Director and Chief Executive Officer
Mr Stephen Gardiner BEc (Hons), Fellow - CPA Australia, Independent Non-Executive Director
Mr Troy Harry, Non-Executive Director
Ms Katherine Hirschfeld AM, BE(Chem), HonFIEAust, FTSE, FIChemE, FAICD, Independent Non-Executive Director
Dr Agu Kantsler BSc (Hons), PhD, GAICD, FTSE, Independent Non-Executive Director
REGISTERED OFFICE
Level 7, 369 Ann Street, Brisbane, Queensland 4000
Telephone:
+61 7 3181 3800
Facsimile:
+61 7 3181 3855
www.centralpetroleum.com.au
AUDITORS
PricewaterhouseCoopers
480 Queen Street, Brisbane, Queensland 4000
SHARE REGISTER
Computershare Investor Services Pty Limited
Level 1, 200 Mary Street, Brisbane, Queensland 4000
Telephone:
Telephone:
Facsimile:
1300 552 270
+61 3 9415 4000
+61 3 9473 2500
www.computershare.com.au
STOCK EXCHANGE LISTING
Central Petroleum Limited shares are listed on the Australian Securities Exchange under the code CTP.
106 CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
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107
GLOSSARY AND ABBREVIATIONS
CORPORATE DIRECTORY
EBITDA
Earnings before interest, tax, depreciation and amortisation
EBITDAX
Earnings before interest, tax, depreciation, amortisation and exploration costs
GROUP GENERAL COUNSEL AND COMPANY SECRETARY
Mr Daniel White LLB, BCom, LLM
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS
Mr Michael (Mick) McCormack BSurv, GradDipEng, MBA, FAICD, Independent Non-Executive Director, Chair
Mr Leon Devaney BSc MBA, Managing Director and Chief Executive Officer
Mr Stephen Gardiner BEc (Hons), Fellow - CPA Australia, Independent Non-Executive Director
Mr Troy Harry, Non-Executive Director
Ms Katherine Hirschfeld AM, BE(Chem), HonFIEAust, FTSE, FIChemE, FAICD, Independent Non-Executive Director
Dr Agu Kantsler BSc (Hons), PhD, GAICD, FTSE, Independent Non-Executive Director
REGISTERED OFFICE
Level 7, 369 Ann Street, Brisbane, Queensland 4000
+61 7 3181 3800
Telephone:
+61 7 3181 3855
Facsimile:
www.centralpetroleum.com.au
AUDITORS
PricewaterhouseCoopers
480 Queen Street, Brisbane, Queensland 4000
SHARE REGISTER
Computershare Investor Services Pty Limited
Level 1, 200 Mary Street, Brisbane, Queensland 4000
Telephone:
Telephone:
Facsimile:
www.computershare.com.au
1300 552 270
+61 3 9415 4000
+61 3 9473 2500
STOCK EXCHANGE LISTING
Central Petroleum Limited shares are listed on the Australian Securities Exchange under the code CTP.
1P
2C
2P
Bbl
Bopd
CSG
EBIT
EIP
ESOP
GJ
GJe
GSA
KMP
KPI
LTIP
Mcfd
mmbl
PJ
PJe
scfd
STIP
TFR
TJ
TJ/d
Tcf
Proved reserves*
Best estimate contingent resources*
Proved and probable reserves*
barrel of oil (unit of measure)
barrel of oil per day
coal seam gas
Earnings before interest and tax
Executive incentive plan
Executive share option plan
Gigajoule (1 billion joules) (unit of energy measure)
Gigajoule equivalent (oil converted at 5.816 GJe / bbl)
Gas sale agreement
Key management personnel
Key performance indicator
Long term incentive plan
Thousand cubic feet per day
Million barrels
Petajoules (1,000 TJ) (unit of energy measure)
Petajoule equivalent (oil converted at 5.816 PJe / mmbbl)
Standard cubic feet per day
Short term incentive plan
Total fixed remuneration
Terajoule (1,000 GJ) (unit of energy measure)
Terajoules per day
Trillion cubic feet (unit of measure)
* As defined by Petroleum Resources Management System (PRMS) 2018 published by the Society of Petroleum Engineers.
106 CENTRAL PETROLEUM LIMITED 2022 ANNUAL REPORT
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107