2021
ACN 083 254 308
Central Petroleum Limited
Annual Report
TABLE OF CONTENTS
CHAIR’S LETTER ............................................................................................................................................................................1
CHIEF EXECUTIVE OFFICER’S LETTER ..............................................................................................................................2
OPERATING AND FINANCIAL REVIEW ............................................................................................................................. 3
DIRECTORS’ REPORT .............................................................................................................................................................. 28
EXECUTIVE SUMMARY – REMUNERATION ................................................................................................................... 34
REMUNERATION REPORT ..................................................................................................................................................... 35
AUDITOR’S INDEPENDENCE DECLARATION .............................................................................................................. 50
FINANCIAL REPORT .................................................................................................................................................................. 51
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME ........................................................................... 52
CONSOLIDATED BALANCE SHEET................................................................................................................................... 53
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY ....................................................................................... 54
CONSOLIDATED STATEMENT OF CASH FLOWS ...................................................................................................... 55
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS ............................................................................... 56
DIRECTORS’ DECLARATION ................................................................................................................................................ 99
INDEPENDENT AUDITOR’S REPORT .............................................................................................................................. 100
ASX ADDITIONAL INFORMATION ................................................................................................................................... 105
CORPORATE GOVERNANCE STATEMENT ................................................................................................................. 106
INTERESTS IN PETROLEUM PERMITS AND PIPELINE LICENCES ..................................................................... 107
CORPORATE DIRECTORY ................................................................................................................................................... 109
__________________
Cover photos (clockwise from top left)
Front cover: Drilling at Range-7, April 2021; Maintenance at the Dingo gas processing facility, Brewer Estate, December 2020; Water Truck at WM27, July 2021; and operations at
the Mereenie Central Treatment Plant (CTP)
Back cover: Drilling at Range-7, April 2021; Equipment at the Mereenie CTP; Aerial view of the Mereenie CTP and associated facilities; and drilling at WM27, July 2021
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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
CHAIR’S LETTER
Dear Shareholders
When I wrote to shareholders in February this year with
Central’s half year report, we had regained some momentum
following the market disruptions of 2020 and had set the
foundations for the implementation of a series of important
growth initiatives.
I am pleased to report that we are making good progress on
these initiatives:
• Our three-well Range CSG pilot has been drilled and testing
is underway, together with progressing two additional step-
out wells, as we work towards a final investment decision.
•
In the Northern Territory, we have recompleted four wells
and drilled two new production wells which will soon be
commissioned, increasing production capacity and
underwriting new gas sale contracts.
• Our two-well exploration program in the Northern Territory
is gathering momentum for an October start, with
equipment being staged for use. If successful, Central could
significantly increase its gas reserves from these targets
and provide a catalyst for increased gas sales into the east
coast gas market.
Strategically, a partial sell-down of our interest in the Amadeus
Basin producing assets to New Zealand Oil & Gas (NZOG) and
Cue Energy Resources (Cue) is tracking towards completion and
was a significant milestone, crystalising the value that has been
created in those fields in recent years and supporting an
increased focus on implementing new growth initiatives.
Energy markets have continued to strengthen from their lows in
early 2020, and with the Federal Government promoting the
importance of natural gas through its Energy Plan announced
during the year, gas is set to continue playing an important role
in Australia’s transition towards reliable low-carbon energy.
We are determined to play an increasing role in Australia’s
energy future by executing our growth strategy, and this will
require significant investment in new projects.
Our investment in recent years has been focussed on increasing
production capacity from our dependable, long-producing fields
in the Amadeus Basin to meet the commissioning of the
Northern Gas Pipeline in 2019. Production from those fields
tripled between 2017 and 2020 as a result of our successful gas
acceleration program, and we have now taken the opportunity
to recycle some of this increased value back into new growth
programs through the partial sell-down to NZOG and Cue.
The introduction of NZOG and Cue will result in over $100
million of investment in these fields in the next two years,
allowing Central to divert more of its resources to its other
potentially high-yielding, growth-orientated opportunities in the
Amadeus, Surat and beyond.
The Amadeus Basin remains significantly underexplored and
Central will now refocus on unlocking some of its resources from
our extensive holdings in the area.
In recent times, there has been much debate about the future of
fossil fuels, and we believe Central can play an important role in
the transition to a cleaner energy future. Compared to coal, our
natural gas is a lower-emitting transitional fuel and is likely to be
in demand as a reliable energy source for many years to come.
The value of our portfolio, however, is not limited to
hydrocarbons. Relatively high concentrations of valuable, and
much sought after, Helium have been measured at some of our
exploration wells, as have traces of naturally occurring
Hydrogen, which many perceive as the next carbon-free energy
source. These other non-hydrocarbon gases potentially have
significant value, and our future exploration programs will seek
to confirm their prevalence in the Amadeus Basin.
Across our operations our environmental footprint remains
relatively small. Our gas contains low concentrations of CO2 that
does not need to be extracted or discharged. We use proven
conventional drilling techniques to extract our gas and our
planned development and exploration programs do not require
fracking.
We continue to value the long-term relationships with our local
stakeholders, Traditional Owners and landholders in the areas in
which we operate, providing employment and business
opportunities in these local communities, while protecting the
environment in which they live. I thank them for their continued
support.
I will also take a moment to reflect on some of our other
achievements this year. Importantly, regarding our financial
performance, our underlying earnings before interest, tax,
depreciation and exploration costs (EBITDAX), at $26.1 million
were 4% higher than that of the previous year. This was a solid
result on lower production volumes, and our closing cash
balance of $37.2 million has us in a strong position from which
to progress our growth strategies.
At a Board level, we have taken the opportunity to complement
the existing suite of skills, welcoming Stephen Gardiner as a
Director. He brings extensive finance experience to the Board at
a critical juncture in our growth strategy. We also farewelled
Director Julian Fowles and long-standing Director and interim
Chair, Wrix Gasteen. We thank them for their service during
Central’s transformation.
I thank our CEO Leon Devaney and his team at Central for their
efforts over the last year in ensuring our supply to customers
was not disrupted by the pandemic, for continuing our excellent
safety record, for the ongoing work on the new wells and
exploration initiatives, and for their efforts in bringing the asset
sale towards completion.
Our strategy now is very clear: to unlock the resources in our
portfolio and bring them to market. The foundations have been
set and we look forward to sharing our success with our
shareholders as we deliver on our plans in the coming year.
Thank you,
Mick McCormack, Chair
21 September 2021
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
1
CHIEF EXECUTIVE OFFICER’S LETTER
Dear Fellow Shareholders
I’m pleased to release Central’s FY2021 Annual Report which
demonstrates solid financial foundations and significant progress
in our various growth initiatives.
We executed the partial sale of our Amadeus Basin producing
assets which has released capital for the Company without diluting
shareholders during very challenging market conditions. The
estimated book profit of circa $35 million1 reflects the value that
we have created from our asset portfolio and is a great investment
outcome for shareholders given the assets were only acquired
about six years ago with very little equity.
The transaction is a vital pillar of our growth strategy, allowing us
to re-invest profits back into near-term growth projects. This will
accelerate growth in the broader Amadeus Basin, with the
transaction stimulating over $100 million of gross investment in
Central’s producing assets without further cash investment
required from Central. The results of this fully funded activity will
become increasing visible to the market over the next year.
We have not been idle while the transaction process has run its
course. Four wells have already been recompleted and two new
production wells have been drilled to significantly boost Mereenie’s
wellhead capacity to over 40 TJ/d (Mereenie gross JV) up from the
31 TJ/d average produced last quarter. We are also excited to have
seen good gas shows from the Stairway Sandstone, supporting new
appraisal that could ultimately convert the Stairway’s 108 PJs in 2C
resources (gross JV) to 2P reserves. Given the brownfield
economics, incremental production from the Stairway could have a
material impact on Mereenie’s production and field economic life.
We also progressed two new exploration wells at the Palm Valley
and Dingo gas fields which are fully funded through the sale
transaction. With equipment ordered and in transit, we remain
on schedule to start drilling in Q4 of this year.
These two deep exploration wells have the potential to more
than replace Central’s divested reserves within the existing
producing fields. They are target horizons located under
established infrastructure and both formations are known to
produce gas elsewhere in the Amadeus Basin. Success would
provide a strong catalyst to open up further conventional gas
plays across the basin and complement our efforts to pursue the
next phase of new targets in 2022.
We are also focussed on progressing our other larger, potentially
company-changing sub-salt targets in the Amadeus Basin which,
in addition to hydrocarbons, have the potential for commercial
quantities of high-value Helium and Hydrogen. Planning for an
initial seismic acquisition at Zevon later this year is well advanced
and has attracted a grant from the NT Government.
We also continue to engage constructively with our JV partner
and permit Operator (Santos) for progress at our Dukas prospect
with a larger 45% stake (up from 30%).
agreement with Australian Gas Infrastructure Group to be a
foundation customer of a proposed new gas pipeline from the
Amadeus Basin to Moomba provides line of sight for a more
direct, cost-effective route to the deeper gas markets of the
eastern seaboard.
In the Surat Basin, our three-well Range pilot has been drilled,
completed and is already flowing small volumes of gas. The pilot
will provide key production data for the front-end engineering
and design work necessary to reach a final investment decision
for the Range Gas Project. With initial water rates from the pilot
lower than anticipated, we are moving quickly to drill two
additional step-out wells to accelerate our technical
understanding of the field prior to taking FID. The joint venture is
currently targeting FID around March 2023, with the
commencement of first gas anticipated two years after the FID
date. We remain fully committed to Range, which we see as a
valuable gas project with 135 PJ of 2C contingent gas resource
that will become more visible to equity markets as we continue
to progress toward FID.
Our financial performance in FY2021 places us in a strong
position to pursue these growth strategies. Cash balances of
$37.2 million were on hand at 30 June, boosted by the proceeds
from the pre-sale of 3.5 PJ of gas for delivery in 2022/2023. Net
debt was reduced by 32% to $31.3 million, which we expect to
improve further when we pay-down $30 million of debt upon
completion of the NZOG/Cue transaction.
Underlying EBITDAX improved by 4% to $26.1 million, reflecting the
benefits of our cost-reduction programs which offset the lower
revenues (down 8% on FY2020) driven by lower sales volumes
(down 17%). The current commissioning of the new Mereenie
production wells will mitigate this natural field decline in FY2022.
While our cash flows and revenues will be lower following our
recent asset sell-down, the investment in new production and
exploration opportunities has the potential to unlock and create
new value from our portfolio, particularly as we progress toward
drilling our two exploration targets, identifying a drillable
prospect at Zevon and taking FID at Range.
I would like to take this opportunity to thank our dedicated staff
for safely, effectively and efficiently operating our business
throughout the year. I also wish to thank our many stakeholders
for their continued support through a year that has presented a
number of macro and sector challenges.
With a strong foundation and many of our growth initiatives
already underway, we are well placed to deliver on these in
FY2022 and we look forward to sharing our progress in the
coming year.
Success in our exploration programs could be the catalyst for
development of a new route to gas-short southern markets. Our
Leon Devaney, CEO
21 September 2021
1 Subject to a final determination of the completion adjustment and movements in liabilities associated with the Sale Assets between the effective date and actual
completion date.
2
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
OPERATING AND FINANCIAL REVIEW
OPERATING HIGHLIGHTS
•
•
•
•
•
•
•
•
•
Strong annual sales volumes and revenues:
o Volumes 10.3 PJe
o
Revenues $59.8 million
EBITDAX of $26.1 million.
Full year profit of $0.3 million.
Reduced net debt by 32% to $31.3 million and extended loan facility by 12 months to late 2022.
Announcement of a binding agreement to sell down 50% of working interests in Amadeus Basin Producing Assets to help
accelerate exploration, appraisal and development activity across the fields. Central to retain Operatorship of all fields.
Successfully drilled a three well pilot program at the Range CSG Project and commenced testing.
Recompleted four wells and commenced drilling the first of two new production wells at the Mereenie field.
Announced an MOU with Australian Gas Infrastructure Group (AGIG), to participate as a foundation customer to progress
towards a final investment decision on a proposed major new pipeline that would enable Central’s gas to be transported direct to
the Moomba gas supply hub and the larger south-eastern Australian gas markets with significantly greater cost efficiencies.
Strengthened the Board with the appointment of Mr Mick McCormack as Chair and Mr Stephen Gardiner as a Director, both
highly respected industry leaders with proven experience in the energy sector.
Underlying EBITDAX: Increased 4% to $26.1m in FY2021
(Earnings before interest, tax, depreciation, impairment, exploration costs, and
profit on asset disposals)
Operating revenue: Decreased 8% to $59.8m in FY2021
Reserves & Resources decreased from production to 151.7 PJe
Net Debt: decreased by 32% to $31.3 million at 30 June 2021
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
3
OPERATING AND FINANCIAL REVIEW
FINANCIAL REVIEW
The Consolidated Entity had a profit after income tax for the year ended 30 June 2021 of $0.3 million (2020: $5.4 million).
The above result was after expensing exploration costs of $7.7 million (2020: $5.3 million). The Group’s policy is to expense all exploration
costs as incurred.
The table below shows key metrics for the Group:
Key Metrics
Net Sales Volumes
-
-
Natural Gas (TJ)
Oil & Condensate (bbls)
Sales Revenue ($‘000)
Gross Profit ($‘000)
Underlying EBITDAX1 ($‘000)
Underlying EBITDA2 ($’000)
Underlying EBIT3 ($‘000)
Underlying profit/(loss) after tax4 ($’000)
Statutory profit after tax ($‘000)
Net cash inflow from Operations5 ($’000)
Capital expenditure6 ($‘000)
Total
2021
9,820
77,255
59,827
30,975
26,088
18,349
5,846
251
251
24,136
11,792
Total
2020
11,822
89,016
65,046
31,660
25,010
19,733
3,299
(2,982)
5,411
15,727
2,857
Change
% Change
(2,002)
(11,761)
(5,219)
(685)
1,078
(1,384)
2,547
3,233
(5,160)
8,409
8,935
(17)%
(13)%
(8)%
(2)%
4%
(7)%
77%
108%
(95)%
53%
313%
1 Underlying EBITDAX is Earnings before Interest, Tax, Depreciation, Amortisation, Impairment and Exploration costs and profit on disposal of exploration permits
(refer reconciliation below).
2 Underlying EBITDA is Earnings before Interest, Tax, Depreciation, Amortisation, Impairment and profit on disposal of exploration permits.
3 Underlying EBIT is Earnings before Interest, Tax and profit on disposal of exploration permits.
4 Underlying profit / loss after tax is statutory profit after tax, before profit on disposal of exploration permits.
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.
Reconciliation of statutory profit before tax to underlying EBITDAX
Statutory profit before tax
Profit on disposal of exploration permits
Underlying profit/(loss) before tax
Net finance costs
Underlying EBIT
Depreciation and amortisation
Impairment
Underlying EBITDA
Exploration expenses
Underlying EBITDAX
2021
$’000
251
-
251
5,595
5,846
12,503
—
18,349
7,739
26,088
2020
$’000
5,411
(8,393)
(2,982)
6,281
3,299
16,257
177
19,733
5,277
25,010
4
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
Sales Volumes
Sales volumes were 17% lower than FY2020 at 10.3 PJe, reflecting weaker markets in the first half and natural field decline throughout the
year, although supported by the Company’s portfolio of firm long-term gas supply contracts. Two new production wells to be
commissioned at Mereenie by October 2021 are expected to increase overall wellhead capacity to over 40 TJ/d.
Note: Oil converted at 5.816 GJ/bbl.
Sales Revenue
Central recorded sales revenue of $59.8 million, down 8% on FY2020, reflecting the lower sales volumes. Realised prices were up 11% on
FY2020 at $5.83/GJe as global oil prices and domestic gas markets recovered from the lows experienced in early 2020.
Gross Profit
Despite the 17% decline in sales volume, gross profit from operations declined by just 2% year on year. On a per unit basis, production
costs were only 3% higher, benefiting from strategies to manage costs to deliver cost-effective operations, including a reduction in staff
back to 2017 levels.
Other Income
Other income was $8.5 million lower than FY2020 which included $7.7 million as final settlement for the transfer of a 50% interest in the
Range Gas Project and $0.68 million profit on the transfer of exploration tenements. To assist with comparability of this year’s result, we
have reported EBITDAX, EBITDA and EBIT against the underlying results in FY2020, which exclude the gains of $8.4 million.
Depreciation and Amortisation
Non-cash depreciation and amortisation costs decreased from $16.3 million to $12.5 million, reflecting the decrease in production and
lower depreciable asset base.
Net Assets/Liabilities
At 30 June 2021, the Group had a net asset position of $3.7 million, an improvement on FY2020 due to the net profit for the year before
share based payments.
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 $20.9 million (excluding $20.9 million which will be transferred to the incoming joint venturers and
reclassified as held for sale). 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. Upon completion of the sell down of its producing
assets, the Group will make circa $30 million in repayments of its debt facility with Macquarie Bank.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
5
OPERATING AND FINANCIAL REVIEW
Debt
Net debt reduced by 32% to $31.3 million at 30 June 2021. EBITDAX of $26.1 million covered (3.3x) service of loan facilities of $7.9 million.
The outstanding balance of the loan facility at 30 June 2021 was $66.8 million, with $36.0 million due for repayment in FY2022, including
the lump sum repayment to be made from the proceeds of the asset sell down when it completes.
The consolidated debt ratio at 30 June 2021 improved to 0.39 (2020: 0.45). Debt ratio is defined as: Total Debt/Total Assets. Net gearing at
30 June 2021 was 27% (2020: 44% or 36% if re-based to 30 June 2021 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 increased by $11.2 million over the year. Net cash flow from production operations for 2021 was $37.7 million compared to
$29.0 million for 2020, with the increase reflecting the proceeds from the presale of gas in FY2021, partly offset by lower revenue net of
operating expenses and gas purchases.
After payment of $3.9 million of interest costs, $4.2 million of corporate expenses (net of government incentives) and $5.5 million for
exploration activities, net cash flow from operating activities was $24.1 million, up from $15.7 million in 2020. Exploration expenditure in
FY2021 was $2.3 million higher than FY2020, reflecting additional expenditure on the Amadeus exploration program and Range pilot
program and other pre-FID activities.
The net cash surplus from operating activities was partly directed towards $4.8 million of borrowing repayments and $8.0 million was
invested in sustaining capital works, new production wells and security deposits.
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
Operating Data
Gas Sales (TJ)
Oil Sales (barrels)
No. of employees at 30 June
2017
$ MILLION
2018
$ MILLION
2019
$ MILLION
2020
$ MILLION
2021
$ MILLION
24.79
1.90
(24.73)
2.22
2.22
.—
106.82
5.48
(82.17)
(5.96)
0.73
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
2017
2018
2019
2020
2021
3,322
111,380
83
4,842
105,619
89
10,229
97,392
99
11,822
89,016
92
9,820
77,255
85
6
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
OPERATIONS AND ACTIVITIES
Central Petroleum Limited is an emerging 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.
Having increased production from its NT fields three-fold since 2017, Central is now focussed on a new multi-faceted growth strategy:
Increasing production capacity from its existing fields. Two new production wells will be online at Mereenie by October 2021;
Developing the Range CSG project in Queensland’s productive Surat Basin. The pilot is currently producing gas and a final investment
•
decision around March 2023 is being targeted, with the commencement of first gas anticipated two years later;
•
Near-term exploration targeting additional gas resources at Central’s NT producing fields. Two new wells will be drilled, starting late
2021. Others are planned for 2022; and
•
Exploration targeting larger multi-Tcf sub-salt targets in the Amadeus Basin which are also prospective for Helium and Hydrogen.
•
Central is also working with Australian Gas Infrastructure Group (AGIG) to progress the proposed Amadeus to Moomba Gas Pipeline to a
FID. The proposed pipeline promises to provide a more direct, cost-efficient route to eastern gas markets.
Through its existing production base, new development projects and enormous exploration
potential, Central is well-positioned to play an increasing role in Australia’s energy future.
Producing Assets
Sales Volumes (Central Petroleum’s Share)
Product
Gas
Crude and Condensate
Total
Unit
PJ
bbls
PJe
FY 2021
FY 2020
9.8
77,255
11.8
89,016
10.3
12.3
Note: Oil is converted to Petajoule equivalent (PJe) at 5.816 GJe/bbl.
Sales volumes were 17% lower than FY2020 at 10.3 PJe, reflecting weaker gas markets in the first half of the financial year and natural field
decline in advance of the commissioning of new production wells by October 2021.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
7
OPERATING AND FINANCIAL REVIEW
Location of Central’s producing oil and gas fields
Mereenie Oil and Gas Field (OL4 and OL5)
Northern Territory
(Central—50% Interest (Operator)1, Macquarie Mereenie Pty Ltd—50% Interest)
Sales volumes
(Central share)
Gas
Crude and Condensate
Unit
PJ
bbl
FY 2021 FY 2020
6.1
89,016
5.3
77,255
Reserves & Resources
(Central share)2
Gas
Oil
Unit
PJ
mmbbl
1P
64.7
0.69
2P
87.2
0.89
2C
91.2
0.10
1 Central’s interest will reduce to 25% upon completion of the asset sale which is expected to settle on 1 October 2021.
2 Reserves and resources are as at 30 June 2021. 2C gas resources include 54 PJ attributable to the Stairway Formation (refer Appraisal Assets - Amadeus Basin
section of this report). Central’s share of Mereenie reserves and resources will reduce by approximately 50% upon completion of the asset sale, which is expected to
settle on 1 October 2021.
The Mereenie oil and gas field was discovered in 1963 and commenced production in 1984, delivering hydrocarbon liquids for sale in South
Australia and gas to Northern Territory markets. A significant expansion program was undertaken to lift firm plant capacity to 44 TJ/d
capacity in time to supply gas to the east coast market through the Northern Gas Pipeline (NGP) in January 2019.
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 thin 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.
Gas production averaged 29.5 TJ/d over the year, down from the 33 TJ/d produced in FY2020. During the first half of FY2021, production
averaged 28.5 TJ/d as markets recovered from the sharp downturn experienced in early 2020. Gas production increased to 30.5 TJ/d in the
2nd half, close to the well capacity of approximately 31 TJ/day at 30 June 2021.
To offset ongoing natural field decline, four existing wells were re-completed in the fourth quarter to access producing zones which were
previously behind pipe. In addition, drilling commenced on the first of two new crestal production wells in June, with both wells expected
to be commissioned by October 2021.
8
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
Palm Valley Gas Field (OL3)
Northern Territory
(Central—100% Interest)1
Sales volumes
(Central share)
Gas
Unit
PJ
FY 2021 FY 2020
3.9
3.2
Reserves & Resources
(Central share)2
Gas
Unit
PJ
1P
21.5
2P
24.4
2C
13.7
1 Central’s interest will reduce to 50% upon completion of the asset sale which is expected to settle on 1 October 2021.
2 Reserves and resources are as at 30 June 2021. Central’s share of Palm Valley reserves and resources will reduce by approximately 50% upon completion of the
asset sale, which is expected to settle on 1 October 2021.
Gas was first discovered at Palm Valley in 1965 and is primarily reservoired in an extensive fracture system in the lower Stairway
Sandstone, Horn Valley Siltstone and Pacoota Sandstone. The anticlinal structure is approximately 29 km in length and 14 km in width. The
field was successfully restarted in 2018 in order to deliver gas into new gas markets made available via the new NGP connection.
The Palm Valley field performance exceeded expectations during the year, averaging 8.9 TJ/d. The PV13 well, commissioned in May 2019,
is declining from its peak production plateau experienced in FY2020, but continues to outperform initial expectations. High production
rates from this well are believed to be supported by ongoing recharge from the fracture network, indicating further outperformance by the
well remains possible.
Following the success of the PV13 well, three further potential locations have been identified for the drilling of new lateral wells similar to
PV13 in order to offset the field’s natural decline. The first of these laterals is expected to be drilled from the Palm Valley Deep exploration
well in early 2022 if the primary exploration target, the deeper Arumbera Sandstone proves unproductive. Other laterals could be drilled
from existing wells for efficient access to additional production capacity.
Dingo Gas Field (L7) and Dingo Pipeline (PL30)
Northern Territory
(Central - 100% Interest)1
Sales volumes
(Central share)
Gas
Unit
PJ
FY 2021 FY 2020
1.2
1.2
Reserves & Resources
(Central share)2
Gas
Unit
PJ
1P
28.0
2P
34.9
2C
—
1 Central’s interest will reduce to 50% upon completion of the asset sale which is expected to settle on 1 October 2021.
2 Reserves and resources are as at 30 June 2021. Central’s share of Dingo reserves and resources will reduce by approximately 50% upon completion of the asset sale,
which is expected to settle on 1 October 2021.
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.
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 were consistent with FY2020, averaging 3.3 TJ/d, meeting 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 2022 for any gas nomination shortfall by the
customer in CY2021.
The Dingo Deep exploration well is expected to be drilled in Q3 FY2022, targeting the deeper Pioneer Sandstone, which has flowed gas at the
nearby Ooraminna prospect, and the Areyonga Formation. The wellhead capacity of the Dingo field is likely to be boosted even if the Pioneer
and Areyonga exploration targets prove unsuccessful, as the well will be completed to access the existing producing Arumbera Sandstone for
tie-in to the Dingo facilities.
Surprise Oil Field (L6)
Northern Territory
(Central—100% Interest)
The Surprise West well produced approximately 88,650 barrels of oil from March 2014 to August 2016 when it was shut in due to low oil
prices and to obtain long term pressure data.
The field remains shut in. A restart may be considered following a sufficient recovery in oil markets. Environmental and reservoir
monitoring continued throughout the year.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
9
OPERATING AND FINANCIAL REVIEW
Appraisal Assets – Amadeus Basin
Mereenie Stairway (OL4 and OL5)
Northern Territory
(Central—50% Interest (Operator)1, Macquarie Mereenie Pty Ltd—50% Interest)
Reserves & Resources
(Central share)2
Gas
Unit
PJ
1P
—
2P
—
2C
54
1 Central’s interest will reduce to 25% upon completion of the asset sale which is expected to settle on 1 October 2021.
2 Reserves and resources are as at 30 June 2021. Central’s share of Mereenie reserves and resources will reduce by approximately 50% upon completion of the asset
sale, which is expected to settle on 1 October 2021.
The recently drilled WM28 production well measured sustained gas flow rates from the Upper Stairway Sandstone of 0.6 mmscfd/d while
drilling through to the deeper Pacoota producing intervals. Whilst the Stairway is typically considered to be tight, the presence of natural
fractures provides sufficient permeability which can be exploited through deviated or horizontal drilling techniques (as occurs in the
Pacoota at Palm Valley).
The successful flow test in the Upper Stairway provides a good indication of the presence of open natural fractures at WM28. This is
consistent with fracture modelling which indicates a high likelihood of natural fractures (predominantly vertical) in the crestal region of the
Mereenie field. Significant flows obtained while drilling through the Stairway have also been recorded in prior development wells,
indicating there could be extensive portions of the Stairway amenable to commercial production with horizontal wells. Further Stairway
appraisal would target those areas with evidence of good flows (such as WM28) to reduce the risk of encountering mineralised fractures,
as was the case in the prior Lower Stairway appraisal well, WM26. Central and its joint venturers at Mereenie will consider appraisal
options for the Stairway at Mereenie.
Drilling at WM27
Photo by Phil Allen
10
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
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
In addition to Central’s producing oil and gas fields in the Northern Territory, Central and joint venturer, Incitec Pivot Limited, are working
towards a final investment decision (FID) for the Range coal seam gas (CSG) project in Queensland’s gas-rich Surat Basin.
Central was formally granted the Authority to Prospect (ATP) 2031 in August 2018. The 77km2 block 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.
In 2019, following a successful four well exploration program, 270 PJ of 2C contingent gas resource were certified (Central share 135 PJ)
within the three coal seams. The wells confirmed 30m of average net coal thickness and permeability in line with or better than
expectations. The proven production capacity of the coals in surrounding areas gives Central a high degree of confidence that the 2C
resources can be converted into 2P gas reserves to support a final investment decision.
Range pilot
A three well pilot was drilled in April 2021 and is being
production tested for several months to provide key subsurface
and production data. The three Range pilot wells, Range-6,
Range-7 and Range-8 were successfully drilled to depths of
between 675m and 685m, with net coal of between 26m and
28m across the three coal seams of the Walloon Coal Measures.
The Range pilot consists of three wells closely spaced at 200m
apart, a production water tank, flare and associated pipework.
Each well has been completed with a slotted liner over the three
seams of the Walloon Coal Measures with a downhole pump
installed.
Range pilot site
Testing of the pilot commenced in mid-June and will provide
production data for several months to support a FID. The pilot is intended to provide key information regarding 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.
Gas breakthrough was observed immediately upon commencement of pumping—earlier than expected—indicating the presence of coals
that are fully saturated with gas. The water level in the wells was gradually drawn-down to the pumps and by mid-August aggregate daily
gas rates had reached around 50,000 scfd. These are expected to increase as dewatering continues.
Initial aggregate water rates are lower than anticipated which
implies less capital will be required for water handling,
processing and disposal in the development phase. On the
downside, an extended pilot dewatering period is likely to be
required. To accelerate technical understanding of water and
gas production profiles for FID, the pilot will be expanded with
two new step-out wells (Range 9 and 10) in late 2021. The new
pilot step-out wells will be spaced at a greater distance than the
original pilot wells and tied into the existing water tank.
In parallel with the pilot activities, applications for key State and
Federal approvals are progressing for the planned full field
development. Proposals have been received from several
established infrastructure providers for provision of gas
processing facilities for the full field development.
Gas production from the Range Gas Project is reserved for
domestic use. The joint venture is targeting FID around March
2023, with the commencement of first gas anticipated two years
after the FID date. The Range Gas Project is at the doorstep of
the east coast gas market and could nearly double Central’s
reserve base and annual sales volumes.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
11
Location of the Range Gas Project (ATP 2031) and pilot in relation to other
coal seam gas projects in the Surat Basin
OPERATING AND FINANCIAL REVIEW
Drilling at Range-7
Photo by Alan Johnson
12
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
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 181,875 km2 (72,197 km2 granted
and 109,678 km2 under application).
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. Although the Amadeus Basin has provided reliable, high quality oil and gas since the 1980s, it is relatively
under-explored and it is believed to hold significant untapped potential for decades of reliable, high volume gas supply.
In addition to proven hydrocarbons, the Amadeus basin is also prospective for Helium and Hydrogen. Exploration wells at Mt Kitty and
Magee have shown high concentrations of Helium and Hydrogen in the basin. These high-value non-hydrocarbon gases are generally
associated with sub-salt prospects and provide a key driver for Central in progressing future sub-salt exploration in the basin, such as at the
Zevon and Dukas prospects.
The Amadeus Basin has, to date, been a focus for the majority of Central’s exploration activity, with ~170,000 km2 of areal extent, five
known working petroleum systems and four fields having produced significant quantities of oil and gas.
Notwithstanding its impressive production history, the Amadeus Basin is one of the few remaining large, under-explored, working
hydrocarbon systems onshore Australia, with only a total of 39 exploration wells and ~14,500 km of 2D seismic acquired across the entire
basin. This historic underinvestment can in part be attributed to the lack of pipeline connections to eastern and southern markets prior to
2019 and the small Northern Territory gas market.
The Northern Gas Pipeline, commissioned in early 2019, provides a pathway to an attractive east coast gas market and the proposed
Amadeus to Moomba Gas Pipeline will, if developed, provide a more direct, efficient route to deeper southern markets and is likely to
provide a catalyst for increased exploration in the Amadeus Basin.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
13
OPERATING AND FINANCIAL REVIEW
Detailed play-based exploration analysis has so far identified 115 potential targets (65 gas and 50 oil) within Central’s permits and
application areas in the basin. Central’s exploration plans are presently centred around several high priority targets which can be drilled
conventionally and without stimulation (hydraulic fracturing):
•
Immediate in-field opportunities: Targeting 192 PJ of mean prospective gas resources (96 PJ Central share1), Central expects to
drill two exploration wells starting in late 2021 within its existing production areas at Palm Valley and Dingo, testing deeper
formations which are known to be productive elsewhere in the basin. These wells, if successful, will be able to be tied-in to existing
production facilities relatively quickly and efficiently.
•
Near term opportunities: Targeting 401 PJ of gas and 29 mmbbl of oil (mean prospective resource), the proposed Orange-3 gas
appraisal well and Mamlambo oil exploration well respectively, are currently identified as lower-risk, high reward opportunities
close to productive areas. In addition, recent strong gas shows while drilling through the Stairway Sandstone at Mereenie provides
new technical information supporting further Stairway appraisal work. If successful, appraisal of the Stairway could ultimately
convert up to 108 PJ (gross JV) of 2C resource into 2P reserves, significantly increasing production capacity and the economic life of
the field.
Large sub-salt targets: The Amadeus Basin contains several large, potentially multi-Tcf sub-salt targets that are also prospective for
Helium and Hydrogen. Planning is underway to return to the Dukas prospect and acquire seismic at the Zevon prospect during
FY2022.
•
Amadeus exploration – Immediate in-field opportunities
(OL3 and L7) Amadeus Basin, Northern Territory
(Central – 100% interest) 2
A two well exploration program is scheduled to commence in late 2021 targeting up to 192 PJ of mean prospective gas resources (96 PJ
Central share1). The wells have compelling investment justifications, including rapid commercialisation through proximity to existing
infrastructure, and attractive brownfield economics. The exploration program targets natural fractures within conventional formations.
The Palm Valley Deep and Dingo Deep wells will test deeper reservoirs which have produced gas elsewhere in the region. These wells are
located within the existing Palm Valley and Dingo fields and, if successful, provide the opportunity for low-cost production via tie-in to
existing infrastructure.
If the deeper targets are unsuccessful, the wells can be completed in the shallower producing formations as production wells.
Schematics of the Palm Valley Deep and Dingo Deep exploration wells (not to scale)
1 After completion of the asset sale which is expected to settle on 1 October 2021
2 Central’s interest will reduce to 50% on completion of the asset sale which is expected to settle on 1 October 2021
14
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
Palm Valley Deep
The Palm Valley Deep well will target a mean prospective resource volume of 123 PJ (61.5 PJ net to Central1) in the deep Arumbera
Sandstone (depth circa 3,500m) which is the productive interval at the Dingo field. If the deep test fails, the well will be plugged back and a
1,500m lateral production well will be drilled at the Pacoota level and completed for immediate tie-in to existing infrastructure.
Dingo Deep
The well will be located crestally in the field and target a mean prospective resource volume of 69 PJ (34.5 PJ net to Central1) 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 Ooraminna well at the Pioneer Sandstone level. A successful exploration test will open up a new play fairway in the
basin. The well will also be completed at the productive Arumbera Formation level for tie-in to the Dingo facilities.
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:
Orange-3 (EP82 DSA), targeting a mean prospective gas resource of 401 PJ: The Orange-3 well will target the Arumbera Sandstone, which is
the producing zone at the Dingo field, some 23km to the south-east. The well will also target the deeper Pioneer Sandstone and Areyonga
Formation which are volumetrically significant and close to the existing Dingo pipeline. Results from the Dingo Deep well, which is targeting
the same deeper structures could influence the timing of drilling Orange-3. Total depth for the well is planned at 3,800m.
Mamlambo (L6), targeting a mean prospective resource of 29 mmbbl of oil: The proposed Mamlambo well is a large structure defined on
an existing seismic grid, only 8km from the Surprise oil field. The well is targeting the Lower Stairway Sandstone and the Pacoota
Formation, both of which are proven reservoirs in the Surprise and Mereenie oil and gas fields. Total planned depth for the well is 1,300m.
Although no final investment decision has been made, permitting, approvals and planning for the Orange and Mamlambo wells is well
advanced.
Location map of immediate in-field exploration opportunities
1 After completion of the asset sale which is expected to settle on 1 October 2021
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
15
OPERATING AND FINANCIAL REVIEW
Lead / Prospect
Immediate in-field opportunities – drilling 2021
Dingo Deep
Palm Valley Deep
Aggregate total immediate in-field opportunities
Near-term opportunities
Orange-3
Mamlambo (oil)
Prospective Resource1
Unit
Best estimate
(P50)
Mean
PJ
PJ
PJ
PJ
mmbbl
24.5
37.5
62.0
284.0
24.0
34.5
61.5
96.0
401.0
29.0
Central’s interest in the prospective resources displayed in this table have been adjusted to reflect Central’s reduced interests that would apply following
completion of the asset sale announced on 25 May 2021.
1. Prospective Resource: As first reported to ASX on 7 August 2020. 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 moveable 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 – Large sub-salt targets
Amadeus Basin, Northern Territory
The Amadeus Basin hosts Neoproterozoic aged sub-salt targets within the Heavitree Formation and the fractured granitic basement. The
source of hydrocarbons for the sub-salt play is provided by the organic rich rocks at the base of the Gillen Formation, and the seal is
provided 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 Neoproterozoic sub-salt section of the Amadeus Basin.
Evidence of a working system for Helium and Hydrogen is provided by gas compositions from the Mt. Kitty-1 and Magee-1 wells, which
recorded 9% and 6% Helium respectively, in combination with hydrocarbon gases and Nitrogen on well test. In addition, 11% Hydrogen was
recorded in Mt. Kitty-1. Helium concentrations above 1% are regarded globally as high, with a concentration of greater than 0.5% regarded
as potentially economic.
A number of large leads exist within the sub-salt play within the Amadeus Basin, including the Dukas prospect in EP112 and the Zevon area
in EP115. Given the potential size of these individual prospects and leads, success at any of these targets would be company changing and
have the potential to unlock a significant new source of gas, Hydrogen and/or Helium for the east coast market.
Dukas (EP112)
(Central – 45% interest, Santos 55%)
Dukas is a geographically large (>400 km2) gas prospect with multi-Tcf potential located in EP112, approximately 175 km south west 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. Up to 2% Helium and 0.5% hydrogen was recovered 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.
The operator, Santos, has been assessing various options to intersect the target formation using specialised high-pressure equipment. A
decision on the forward plan for Dukas is expected in late 2021.
Central’s interest in EP112 increased to 45% in July 2021 following an election by Santos under JV arrangements.
16
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
Zevon (EP115)
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.
The Zevon area is interpreted as a regional-scale basement high, sub-divided into two leads, Zevon East (180km2) and Zevon West
(582 km2). 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 30km experimental seismic line will be acquired in late 2021 to optimise the acquisition parameters for a subsequent larger seismic
program. Work has commenced on planning the larger, circa 700km, 2D seismic survey ahead of identifying a drilling location in the Zevon
area.
Location of Dukas and Zevon sub-salt targets
Southern Amadeus Basin, Northern Territory
Various Exploration Permits (see table on page 107)
In addition to the large sub-salt leads, such as Dukas, 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. The Dingo Deep exploration well
will provide important data on these deeper targets in early 2022, which will feed into the planning for future activities at Ooraminna.
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 107)
The Company 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.
In the Wiso Basin, a gravity survey was conducted by Geoscience Australia and the Northern Territory Geologic Survey in 2013, which has
provided Central with improved detail of structural trends. Interpretation and forward modelling in conjunction with magnetic, borehole
and outcrop data has led to the generation of a depth to basement map. This will help with the planning of a proposed seismic acquisition
program which will form part of the first phase of exploration once tenure is granted.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
17
OPERATING AND FINANCIAL REVIEW
ATP909, ATP911 and ATP912
Southern Georgina Basin, Queensland
(CTP—100% interest)
Geology and geophysical studies continued, focussing on the Ethabuka structure.
Helium and Hydrogen potential of the Amadeus Basin
Helium is the second lightest and second most abundant element in the Universe. It is used as a cooling agent for MRI’s, super conducting
magnets, satellite instrumentation, leak detection, car airbags, welding Aluminium, and mixed with Oxygen for deep sea diving.
Helium is exceptionally rare on Earth as the Earth’s crust is only about 8 parts per billion Helium. Currently, all Helium production is derived
as a by-product of hydrocarbon bearing gas accumulations. In 2019, there were only 16 Helium plants wordwide which refine Helium into a
liquid form. The US was the largest producer (53% share worldwide) and had the largest Helium reserves. The price of bulk liquid Helium
has increased by 250% in the last decade.
In Australia, the only commercial quantities of Helium are extracted from the tail of LNG production at the Darwin LNG plant, which is fed
by gas from the Bayu-Undan field in the Timor Sea. Helium is present in concentrations of 0.1% in the raw gas and becomes enriched in the
tail gas of the LNG process to 3% whereupon it is utilised as feedstock for Helium extraction.
The Amadeus Basin is highly prospective for Helium and Hydrogen due to a combination of a radiogenic granitic source in the basement
and the presence of thick evaporitic seals which immediately overlies the fractured basement and the Heavitree Formation, both of which
act as potential reservoirs.
Evidence of a working system for Helium and Hydrogen is provided by gas compositions from the Mt. Kitty-1 and Magee-1 wells, which
recorded 9% and 6% Helium respectively in combination with hydrocarbon gasses and Nitrogen on well test. In addition, 11% Hydrogen
was recorded in Mt. Kitty-1. Helium concentrations above 1% are regarded globally as high, with a concentration of greater than 0.5%
regarded as potentially economic.
A Helium play map for the Amadeus Basin has been constructed in-house by identifying areas which contain the critical geological elements
required to make a potential Helium discovery (below).
Amadeus Basin Helium play map
18
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
COMMERCIAL
Sell-down of Amadeus Production Assets
On 25 May, Central announced it had entered into a binding agreement to sell 50% of its current working interest in its Amadeus Basin
Production Assets to entities controlled by New Zealand Oil and Gas Limited (“NZOG”) and Cue Energy Resources Limited (“Cue”) (the
“NZOG Entities”) for total consideration valued at circa $85 million (the “Transaction”).
The assets being sold under the Transaction consist of 50% of Central’s interests in its producing assets in the Northern Territory, namely,
the Mereenie Oil and Gas Field (OL 4/5) (“Mereenie”); Palm Valley Gas Field (OL3) (“Palm Valley”); and Dingo Gas Field (L7) (“Dingo”)
(together, the “Production Assets”).
The Transaction comprises a sale of a 50% interest in Central’s share of the Production Assets, with an effective date of 1 July 2020 in
return for consideration comprising of:
an upfront cash payment of $29 million;
•
•
•
$40 million payment by way of “carried” funding for Central’s share of near-term development, appraisal and exploration activities;
$23 million (Central’s book value at the effective date) through an assumption by the NZOG Entities of obligations to supply up to
4.9 PJ of gas (50% interest acquired at the effective date) which has previously been paid for but not delivered under pre-sale or ‘take-
or-pay’ arrangements; and
a completion adjustment for net cash flows generated between the effective date and the completion date.
•
The Transaction “carry” of $40 million net to Central covers payment of certain of Central’s JV expenditure obligations for near-term
development and growth activities across the Production Assets with a total gross JV cost of over $100 million. This includes two
committed exploration wells to commence later this year (Palm Valley Deep and Dingo Deep, with options to complete these wells as
producers from the existing production intervals) as well as two production wells at Mereenie which will be commissioned in the first
quarter of FY2022.
Central will repay circa $30 million of the Macquarie Bank loan facility at completion.
The Transaction is expected to complete on 1 October 2021 and result in an after-tax accounting profit net to Central of circa $35 million
on the sale1.
Transaction meets strategic objectives and opens multiple avenues for growth
Value accretive
$85m consideration(1) for 50%, with an expected circa $35m profit(1), delivers a strong signal for the
underlying value and quality of Central’s Amadeus Basin Producing Assets
Accelerates Growth
Provides $40m free-carry for near term exploration and development, which would facilitate
approximately $100m (gross JV) investment across the Sale Assets without any further cash outlay from
Central
Diversifies risk
Accelerates growth in the Amadeus Basin while sharing and diversifying geological, exploration and
development risk through a new joint venture
Aligned partner
Introduces technically capable partner(s) with financial capacity and aligned objectives
Operatorship
Central retains operatorship
Balance Sheet
Strengthens Central’s balance sheet through reduction of debt (by $30m) and deferred gas liabilities
(by $21m)(2)
1 Estimated value if the transaction completed on 1 August 2021 and subject to final determination of the completion adjustment and movements in liabilities
associated with the Sale Assets between the effective date and the actual completion date.
2 Based on Central’s book value for these liabilities at the effective date, including pre-sale subsequently executed in December 2020.
Central retains its existing interests in significant growth opportunities not included in the Transaction, including: the Range Coal Seam Gas
Project (50%); EP82 Dingo Satellite Area (“DSA”) including the Orange-3 target (100%); Mamlambo oil target close to the Surprise oil field in
L6 (100%); EP115 including the Zevon multi-Tcf sub-salt target (100%); and EP112 including the Dukas multi-Tcf sub-salt target (45%).
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
19
OPERATING AND FINANCIAL REVIEW
Amadeus to Moomba Gas Pipeline (AMGP)
In August 2020, Central (as a potential foundation customer) executed a Memorandum of Understanding with its Mereenie JV partner,
Macquarie Mereenie Pty Ltd and Australian Gas Infrastructure Group (AGIG) to progress towards FID for the development of a new 950km
gas pipeline from the Amadeus Basin to the Moomba gas hub.
The proposed Amadeus to Moomba Gas Pipeline (AMGP) would cut 1,250 km from the current route to Moomba, offering more cost-
efficient access to the deeper, higher-priced gas markets of south-eastern Australia.
The AMGP project is already well defined, having previously completed front-end engineering and design as the subject of a firm offer by
AGIG under the North East Gas Interconnect selection process conducted in 2015.
Central’s operated fields in the Amadeus Basin have approximately 200 PJ of uncontracted conventional gas reserves (gross JV) which can
be supplied to market through the AMGP. Further foundation supplies from Central’s operated gas fields will be required for FID.
Two exploration wells, set to start drilling in late 2021, are targeting an additional 192 PJ of mean prospective gas resources (gross JV). Gas
discoveries resulting from this exploration program or Central’s future NT exploration activity in the underexplored, but highly prospective
Amadeus Basin (including Orange, Zevon and Dukas), could be a catalyst for the development the AMGP.
Gas pipeline infrastructure and the proposed
Amadeus to Moomba Gas Pipeline (AMGP)
20
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
RESERVES AND RESOURCES STATEMENT
Net proved & probable (2P) oil and gas reserves were 151.7 PJE at 30 June 2021.
Upon completion of the partial asset sale announced on 25 May 2021, Central’s interest in the reserves and resources set out below at
Mereenie, Palm Valley and Dingo will be reduced by approximately 50%.
Aggregate Reserves and Resources
As at
1 July 2020 –
30 June 2021
As at
Comprising1
30/06/2020
Production
30/06/2021
Developed
Undeveloped
Oil
Proved reserves (1P)
Proved plus probable reserves (2P)
Contingent Resources (2C)
Gas
Proved reserves (1P)
Proved plus probable reserves (2P)
Contingent Resources (2C)
mmbbl
mmbbl
mmbbl
0.77
0.97
0.10
PJ
PJ
PJ
123.24
155.56
239.88
(0.08)
(0.08)
—
(9.07)
(9.07)
—
0.69
0.89
0.10
114.18
146.50
239.88
0.47
0.75
—
81.22
115.58
—
0.22
0.14
—
32.96
30.92
—
1
All developed and undeveloped 1P and 2P reserves are located in the Amadeus Basin geographical area.
Reserves and Resources by Field
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
PJ
Note: Estimates may not arithmetically balance due to rounding.
As at
30/06/2020
1 July 2020 –
30 June 2021
Production
As at
30/06/2021
0.77
0.97
0.10
69.26
91.82
91.20
24.73
27.66
13.68
29.26
36.08
(0.08)
(0.08)
—
(4.61)
(4.61)
—
(3.24)
(3.24)
—
(1.22)
(1.22)
0.69
0.89
0.10
64.65
87.22
91.20
21.49
24.42
13.68
28.04
34.86
135.00
—
135.00
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 Development &
Appraisal 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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
21
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 Development and
Appraisal 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 risk is inherent in our business and the effective management of risk is vital to deliver 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 and considers 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 and the transition to a lower-carbon economy influences Central Petroleum’s strategy, presenting both risk and
opportunity in the operation of our existing assets and commercialisation of our growth portfolio. We aim to leverage our risk
management framework to ensure an integrated and coordinated approach to the management of climate change across the business.
Principal risks and uncertainties at 30 June 2021
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
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 anti-bribery and corruption laws
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 2021 ANNUAL REPORT
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.
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 utilize an established project management
framework which is supported by skilled and
experienced personnel to govern and deliver major
projects.
Oil and Gas Reserves
Commercialisation of
hydrocarbons reserves is a
key contributor to our long-
term success.
Climate Change
Climate change is impacting
the way that the world
produces and consumes
energy.
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.
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.
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.
We are focused on ensuring our portfolio is robust in
a potentially carbon constrained market and engage
proactively with key industry and government
stakeholders. Our development is predominantly
focused on gas as a transition fuel which could see
demand for natural gas increase in the medium term
as part of a transition to a clean energy future
compared to other hydrocarbon 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
hydrocarbon by targeting valuable non-hydrocarbon
gases such as Helium and naturally occurring
Hydrogen which have been measured in some of its
exploration tenements.
Community
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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
23
OPERATING AND FINANCIAL REVIEW
Context
Risk
Mitigation
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 and the potential
transmission to 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 a Pandemic (COVID-19)
Management Plan. Although we continue our
support, we are limiting company-initiated face to
face engagement with traditional owner
communities. 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.
Our operational performance is based on 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 infrastructure to maximise reliable and
safe operations.
Central maintains insurance in line with industry
practice and 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 a Pandemic (COVID-19)
Management Plan to minimise the risk of impacts to
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.
Central’s focus remains on securing and developing
the right people to support the development of our
portfolio of assets and opportunities. Our focus
remains on creating a positive employer value
proposition, planning our resource requirements and
attracting talented individuals. We also proactively
engage contractors to supplement any short-term
gaps in capability and capacity to support the
execution of our business plans.
24
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
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 in
the form of the Australian Domestic Gas Supply
Mechanism; although this mechanism is
focused on availability of supply and is not
considered to have significant potential 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 capitalized 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 10% of
consolidated sales revenue in FY2021.
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, multiple data
back-ups and security monitoring software. We are
continuing to embed a cyber-safe culture across
Central.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
25
OPERATING AND FINANCIAL REVIEW
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 new 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.
SUSTAINABILITY AND COMMUNITY
Central Petroleum takes its responsibilities to the environment, landowners and cultural heritage very seriously – 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.
Environmental
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 waste and water 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 95%
compliance with no non-compliances noted. There were no reportable environmental incidents during the year.
No fracture stimulation (fracking) activities are conducted in our production or exploration areas.
Climate change and emissions
Central recognises that climate change is an increasingly significant environmental, social, and business issue. We believe that natural gas
plays a pivotal role in providing cleaner, affordable, and reliable energy under a coordinated approach with our governments and
communities as we transition to a lower-emission energy future.
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, FY2020, our share of scope 1 and 2 emissions across our operations was 47,545 tons of CO2e. 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. As older legacy equipment is
replaced, we are installing more efficient appliances which will further reduce Scope 1 emissions across our operations.
26
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
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.
Zebra finches near WM27 drilling site
Photo by Phil Allen
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 in return we seek to provide employment and business opportunities to our local communities.
In the Northern Territory, for example:
59% of our staff live locally
30% of our staff are indigenous
•
We paid over $4.0M of Royalties to the Northern Territory and Central Land Council in FY2021.
•
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.
Other high-value, non-hydrocarbon gases
Central’s Amadeus Basin tenements are also prospective for other high-value, non-hydrocarbon gases such as Helium and Hydrogen.
Radiogenic basement rocks and an evaporitic sealing unit have created the ideal conditions for a Helium and Hydrogen play in the sub-
salt section of the Amadeus Basin.
The Mt Kitty-1 well recorded gas composition including 9% Helium and 11% Hydrogen. Helium has also been measured at the Magee-1
and Dukas-1 wells.
Central views the opportunity to discover and commercially produce these high-value non-hydrocarbon gasses as a growing and
important aspect of our exploration and business development strategies.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
27
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2021
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 2021.
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.
Current Directors:
Mr Michael (Mick) McCormack (Chair, appointed as Director on 1 September 2020)
Mr Leon Devaney (Managing Director)
Mr Stuart Baker
Mr Stephen Gardiner (appointed 1 July 2021)
Ms Katherine Hirschfeld AM
Dr Agu Kantsler
Former Directors:
Dr Julian Fowles (resigned 31 October 2020)
Mr Wrixon Gasteen (resigned 28 November 2020)
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 (2020: $Nil). No recommendation for payment of dividends has been made.
OPERATING AND FINANCIAL REVIEW
The operating and financial highlights for the financial year were:
•
•
•
•
•
•
•
•
•
Strong annual sales volumes and revenues:
o Volumes 10.3 PJe
o
Revenues $59.8 million.
EBITDAX of $26.1 million.
Full year profit of $0.3 million.
Reduced net debt by 32% to $31.3 million and extended loan facility by 12 months to late 2022.
Announcement of a binding agreement to sell down 50% of working interests in Amadeus Basin Producing Assets to help
accelerate exploration, appraisal and development activity across the fields. Central to retain Operatorship of all fields.
Successfully drilled a three well pilot program at the Range CSG Project and commenced testing.
Recompleted four wells and commenced drilling the first of two new production wells at the Mereenie field.
Announced an MOU with Australian Gas Infrastructure Group (AGIG), to participate as a foundation customer to progress
towards a final investment decision on a proposed major new pipeline that would enable Central’s gas to be transported direct to
the Moomba gas supply hub and the larger south-eastern Australian gas markets with significantly greater cost efficiencies.
Strengthened the Board with the appointment of Mr Mick McCormack as Chair and Mr Stephen Gardiner as a Director, both
highly respected industry leaders with extensive experience in the energy sector.
A detailed review of the operating and financial performance for the year ended 30 June 2021, including principal risks is provided from
pages 3 to 27 of this Annual Report.
28
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
SIGNIFICANT CHANGES IN THE STATE OF AFFAIRS
The financial position and performance of the Group was particularly affected by the following events and transactions during the year
ended 30 June 2021:
•
•
•
•
•
•
Strengthening oil & gas markets and implementation of cost control initiatives resulted in a 4% increase in underlying EBITDAX
from the previous year.
Announcement of a binding agreement to sell down 50% of working interests in Amadeus Basin Producing Assets to help
accelerate exploration, appraisal and development activity across the fields. Central to retain Operatorship of all fields.
Successfully drilled a three well pilot program at the Range CSG Project and commenced testing.
Recompleted four wells and commenced drilling the first of two new production wells at the Mereenie field.
Pre-sold 3.5 PJ of gas for delivery in 2022/2023.
Announced an MOU with Australian Gas Infrastructure Group (AGIG), to participate as a foundation customer to progress
towards a final investment decision on a proposed major new pipeline that would enable Central’s gas to be transported direct to
the Moomba gas supply hub and the larger south-eastern Australian gas markets with significantly greater cost efficiencies.
There were no other significant events that are not detailed elsewhere in this Annual Report.
EVENTS SINCE THE END OF THE FINANCIAL YEAR
Increased interest in EP112
Effective 31 July 2021, Central’s interest in EP112 increased from 30% to 45% as a result of joint venturer, Santos, not electing that Central
be carried for the first $3,000,000 of future Dukas well costs.
Asset Sale
On 17 September 2021 the agreement for the sale of 50% of the Group’s producing assets to New Zealand Oil & Gas Limited and Cue
Energy Resources Limited became unconditional and the transaction is expected to complete on 1 October 2021.
No other matter or circumstance has arisen between 30 June 2021 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 partial sell-down of Central’s producing assets is expected to complete on 1 October 2021 and provide Central with the opportunity to
accelerate its growth plans for the broader Amadeus Basin. The transaction will stimulate over $100 million of gross investment in Central’s
producing assets without further cash input from Central and allow the retirement of $30 million of debt.
Two new production wells at Mereenie will be commissioned in Q1 FY2022 and are expected to significantly boost production capacity
back to over 40 TJ/d (Mereenie gross JV). While Central’s share of production and reserves will be lower following the completion of the
sell-down, two new exploration wells will be drilled in FY2022 at the Palm Valley and Dingo gas fields (which are fully funded through the
sale transaction) and have the potential to replace Central’s divested gas reserves.
Success at Palm Valley Deep and Dingo Deep would provide a strong catalyst to open up further conventional gas plays across the basin
and complement Central’s efforts to support the development of a new pipeline route to gas-short southern markets via Moomba.
Central is also focussed on progressing its other larger, potentially company-changing, sub-salt targets in the Amadeus Basin which in
addition to hydrocarbons, have the potential for commercial quantities of high-value Helium and Hydrogen. A return to the promising
Dukas well is being planned and an initial seismic line will be shot at Zevon later this year in advance of a larger seismic acquisition program
in the second half of FY2022.
The three well pilot at Central’s Range CSG project in Queensland will be expanded with two new wells in late 2021, as Central advances
towards a final investment decision, targeted for around March 2023.
Further information on these activities is included from pages 1 to 27 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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
29
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2021
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 37 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 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: Managing Director of APA Group (Australian Pipeline
Limited) from 2006 to 2019, 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 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 Stuart Baker BE(Elec), MBA. Member, AICD
Independent Non-executive Director
Mr Baker has been a Director of Central Petroleum Limited since December 2018 and has more than four decades of
experience in the oil and gas sector. He currently provides independent advice to corporates in the Australian oil and
gas industry. He is a member of the Investment Committee of the ASX-listed Lowell Resources Funds Management Ltd
(ASX:LRT).
Previously he was Executive Director at Morgan Stanley with dual roles of Co-Head Asia Oil, Gas and Chemicals
Research and team leader for research on Australian Energy, Mining and Utility sectors, with positions held over a
13 year period.
He also held senior equity research positions in oil and gas, at Macquarie Bank and Bankers Trust in aggregate for
12 years. Prior to joining the financial services industry, Mr Baker worked at numerous oil and gas exploration and
production locations throughout South-East Asia, as a senior engineer for the multi-national Houston-based oil service
provider, Schlumberger Ltd.
30
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
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.
Ms Katherine Hirschfeld AM BE(Chem) UQ, HonFIEAust, FTSE, FIChemE, FAICD
Independent Non-executive Director
Ms Hirschfeld was appointed as a Director in 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 Qld Urban Utilities.
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 and Snowy Hydro.
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.
Directorships of other listed companies in the last three years: Tox Free Solutions Limited from 2013 to 2018.
Dr Agu Kantsler BSc (Hons), PhD, GAICD, FTSE
Independent Non-executive Director
Dr Kantsler joined the Central Board in 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 Non-executive Director of Oil Search Limited since 2010 and a former President of
the Chamber of Commerce and Industry WA.
Directorships of other listed companies in the last three years: Oil Search Limited from 2010.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
31
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2021
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.
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
Julian Fowles3
Wrixon Gasteen4
Katherine Hirschfeld AM
Agu Kantsler
Michael McCormack5
Full Meeting of
Directors
Audit & Financial Risk
Committee
Risk & Sustainability
Committee
Remuneration &
Nominations Committee
Eligible1
Attended
Eligible1
Attended2
Eligible1
Attended2
Eligible1
Attended2
12
12
3
6
12
12
11
12
12
3
6
12
12
11
4
—
—
2
4
—
3
4
4
1
2
4
4
4
—
—
1
2
4
3
3
4
4
1
2
4
4
4
10
—
4
6
—
7
4
10
8
4
5
7
8
7
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 Julian Fowles resigned 31 October 2020.
4 Wrixon Gasteen resigned 28 November 2020.
5 Michael McCormack was appointed 1 September 2020.
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.
(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
18,151,116
(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 our environmental conditions outlined in applicable
Environmental Management Plans over the course of the year identified over 95% compliance with no non-compliances noted. There were
no reportable environmental incidents during the year.
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.
32
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
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 50.
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.
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
2021
$
9,129
26,864
35,993
2020
$
14,657
26,092
40,749
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
33
EXECUTIVE SUMMARY – REMUNERATION
The LTIP’s Absolute TSR performance for the three years from
1 July 2018 to 30 June 2021 failed to achieve the minimum
growth hurdle of 10% pa. Whilst disappointing, Central’s share
price performance over this period was not inconsistent with
that of its peers and the Relative TSR placed Central above the
50th percentile compared to its peers, resulting in 31.5% of
rights vesting for this three year performance period. As
included in the LTIP plan rules, the Board has discretion to retest
performance of these hurdles at 31 December 2021.
With increasingly competitive labour markets, the Board has
undertaken an external review of our incentive schemes with
the aim of ensuring alignment with our short-term priorities and
longer-term strategies.
We are cognizant that the success of our transformational
growth programs in the next couple of years, both in the
Amadeus and at the Range CSG Project, are critical to delivering
shareholder value. As a result, we are re-weighting our incentive
schemes to deliver more reward for near-term performance.
For FY2022 our executive team will participate in an incentive
program that integrates short and long-term components.
Performance against our KPI targets in FY2022 will determine
the size of the earned reward, with most of the value converting
into share rights vesting over the following three years.
Other key members of staff will share in a broader short-term
cash incentive plan targeting near-term performance in lieu of
future participation in the equity-based LTIP of previous years.
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.
We are confident the remuneration decisions taken this year will
meet the expectations of our shareholders and look forward to
sharing the success as we pursue our growth plans.
Michael (Mick) McCormack
Remuneration and Nominations Committee Chair
Dear Shareholders,
Having successfully weathered the pandemic related market
disruptions of 2020, Central emerged in FY2021 in a strong
position to resume its growth-focused strategy. The sale of 50%
of our operating assets to New Zealand Oil & Gas and Cue
Energy Resources releases significant funding to support our
growth. There has been much activity on executing our growth
strategy, with pilot wells drilled at the Range Coal Seam Gas
(CSG) Project, production wells drilling at Mereenie and new
exploration wells at Palm Valley and Dingo set to commence
drilling later this year.
Attracting and retaining key personnel to progress these
activities is a key priority. Competition for experienced
personnel is rising as the rebound in oil and gas markets has
seen increased activity across the industry at a time when access
to international workers remains restricted.
To maintain a competitive remuneration structure in these
market conditions and to provide targeted performance
incentives, we have made some adjustments across all the
components for FY2022: fixed remuneration; short term
incentives; and long term incentives, which are summarised
below.
Fixed remuneration
Fixed remuneration was frozen at July 2019 levels for FY2021,
consistent with the market in mid-2020, and will increase by
approximately 2% in July 2021. Staff will also benefit from the
0.5% increase in compulsory superannuation contributions.
2021 STIP
The Short Term Incentive Plan (STIP) is designed to reward
personnel for outcomes above expected performance.
Achievement of short term incentives depends on achieving
personal and corporate objectives over the year, providing an
opportunity to earn up to 10% of base remuneration.
Notwithstanding difficult business conditions in CY2020 that
negatively impacted production and sales, the Company was
successful in achieving safety and cultural heritage KPIs,
exceeded its revenue targets, successfully controlled costs and
successfully drilled and commissioned the Range pilot. We also
reached agreement with the NZOG group to sell 50% of our
production assets, with a significant book profit expected to be
realised. As a result, personnel were entitled to an average 6.7%
of their maximum 10% incentive for the year.
2021 LTIP
Long term incentives are designed to align management’s
interests directly with those of shareholders. The Employee
Rights Plan / Long Term Incentive Plan (LTIP) targets half of its
reward outcomes to Central’s shares outperforming those of its
peer group (Relative Total Shareholder Returns) and half to
Absolute Total Shareholder Returns (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.
34
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
REMUNERATION REPORT
(AUDITED)
This Remuneration Report for the year ended 30 June 2021 (FY2021) 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.
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 (LTIP)
Executive Share Option Plan (ESOP)
Short Term Incentive Plan (STIP)
Executive Incentive Plan (EIP)
Realised Remuneration
Remuneration Details
Executive Service Agreements
Non-Executive Director Fee Arrangements
A. Directors and Key Management Personnel
The Directors and key management personnel of the Consolidated Entity during the year and up to signing date of the annual report were:
Directors
Current Directors:
Mr Michael (Mick) McCormack
Mr Leon Devaney
Mr Stuart Baker
Mr Stephen Gardiner
Ms Katherine Hirschfeld AM
Dr Agu Kantsler
Former Directors:
Dr Julian Fowles
Mr Wrixon Gasteen
Non-executive Chair (appointed 1 September 2020)
Managing Director and Chief Executive Officer
Non-executive Director
Non-executive Director (appointed 1 July 2021)
Non-executive Director
Non-executive Director
Non-executive Director (resigned 31 October 2020)
Non-executive Chair (resigned 28 November 2020)
Other Key Management Personnel
Mr Ross Evans
Mr Damian Galvin
Dr Duncan Lockhart
Mr Robin Polson
Mr Jonathan Snape
Mr Daniel White
Chief Operations Officer
Chief Financial Officer
General Manager Exploration
Chief Commercial Officer (resigned 30 June 2021)
Chief Commercial Officer (appointed 1 July 2021)
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 remuneration strategy incorporates the following metrics:
a. Measuring Central’s achievement of its KPI targets and share appreciation performance against its peers
(Peer company group based on comparative indicators such as market capitalisation, size, complexity of operations and market
developments)
b. Adjusting to remuneration best practice and movements in relevant labour markets
c.
Linking internal strategies to improved shareholder value through achievement of appropriate KPIs.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
35
REMUNERATION REPORT
(AUDITED)
B. Remuneration Overview (continued)
Financial Year 2021
Summary of fixed and variable remuneration outcomes
No general salary
increases in FY2021
Reflecting market conditions in mid-2020, a pay freeze was implemented for the July 2020 pay review,
resulting in no general salary increases for FY2021. As at 1 July 2021, a 2% inflationary pay rise will apply to
eligible employees for FY2022. In addition, employees will benefit from the statutory increase in
compulsory superannuation from 9.5% to 10%.
STIP
LTIP Vesting
Achievement of Company-wide and individual KPIs resulted in payment of an average 67% of the maximum
STIP to eligible employees.
The vesting rate for Share Rights issued under the Long Term Incentive Plan for the three year period
ending 30 June 2021 was 31.5%
2021.
but may, at the Board’s discretion, be eligible for retesting at 31 December
,
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) and the Executive Share Option Plan (ESOP) rather than the Short Term Incentive Plan (STIP).
It is proposed that from FY2022, executives will participate in a revised incentive plan that will combine both short term annual KPIs and a
longer-term, equity-based component (refer Section H below).
For periods up to and ending on 30 June 2021, the remuneration of directors and executives consisted of the following key elements:
Non-executive directors:
1. Fees including statutory superannuation; and
2. No participation in short or long term incentive schemes.
Executives, including executive directors:
1. Annual salary and non-monetary benefits including statutory superannuation;
2. Participation in a Short Term Incentive Plan (performance measured over a 12 month period);
3. Participation in a Long Term Incentive Plans (LTIPs or ESOPs), measured over a 3 year period); and
4. There are no guaranteed base pay increases included in any executive’s contract.
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 2020 review of remuneration. Guerdon Associates were engaged to provide advice
relating to the award of the FY2020 STIP, but they did not provide any specific remuneration recommendation.
The Board appointed Guerdon Associates to provide advice relating to incentive schemes for the FY2022 year, but the reports received did
not provide any specific remuneration recommendations.
36
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
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 2021 which will
vest (Vesting Percentage) as determined by the performance conditions, based on the 20-day VWAP prior to 30 June 2021 of $0.122. The
benchmark share price at the start of the performance period was $0.163:
Hurdle
Definition
Hurdle Banding
Vesting
Percentage
Result for Plan
Year Vesting
30 June 2021
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
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%
Hurdle
Definition
Hurdle Banding
Relative TSR – E&P2
(50% weighting)
Company's TSR relative to a specific
group of exploration and production
companies (determined by the Board
within its discretion) calculated as at
vesting date
1 Total shareholder return (i.e. growth in share price plus dividends reinvested).
2 Exploration and Production.
Result for Plan
Year Vesting
30 June 2021
Vesting
Percentage
Share Rights
Vesting
Company’s Relative TSR
76th percentile and above
100%
From 51st to 75th percentile
50% to 99%
(63%)
Below 51st percentile
0%
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 unvested 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 is 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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
37
REMUNERATION REPORT
(AUDITED)
E. Long Term Incentive Plan – Employee Rights Plan (LTIP) (continued)
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.
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 below);
b. The Executive Management Team (EMT) received a LTIP percentage up to 30% of their TFR until FY2021, with certain EMT
members participating in only the ESOP in FY2020 and FY2021;
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)
iii)
No further LTIPs will be granted under the existing LTIP structure described above from 1 July 2021;
The Managing Director (subject to shareholder approval) and EMT will be eligible to participate in an Executive Incentive Plan
(EIP) from FY2022 (refer Section H below); and
Incentive for employees in categories c, d and e above will be re-weighted to a single STIP opportunity 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
granted over the next three years 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 will be issued for no
consideration, unless otherwise determined by the Board. 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 issued in 2019 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.
38
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
F. Long Term Incentive Plan – Executive Share Option Plan (ESOP)
(continued)
All of a participant's Share Options will lapse on the earliest to occur of:
(i)
the Expiry Date (as stipulated in the offer); or
(ii) 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.
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.
G. Short Term Incentive Plan (STIP)
The Short Term Incentive Plan (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 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.
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).
Key terms and conditions
The Financial Year 2021 STIP (FY2021 STIP) has been holistically designed to recognise and reward individual effort through connecting
individual KPIs and corporate KPIs.
KPI Category
Maximum
Achieved
Percent Allocation of STIP
Corporate KPIs
Safety and Environment KPI’s
Individual KPIs
50 %
10 %
40 %
100 %
25.62 %
9.38 %
32.00 % (avg)
67.00 % (avg)
Performance Outcome for FY2021
0%
50%
75%
100%
Employees could earn a maximum of 10% of TFR from the FY2021 STIP.
Corporate KPIs for FY2021 included:
Objective
Weighting
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
Amadeus to Moomba Gas Pipeline (AMGP)
Assessed against progress on milestones
25%
25%
20%
10%
20%
1 Not rewarded for works that were essential but not completed, e.g. capital project delay or deferral
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
39
REMUNERATION REPORT
(AUDITED)
G. Short Term Incentive Plan (STIP) (continued)
Safety and Environment KPIs for FY2021 included:
Objective
Weighting
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%
Performance Outcome for FY2021
0%
50%
75%
100%
Summary Performance of Company-wide KPI’s
Corporate
Safety and Environment
Total Corporate, Safety & Environment
Maximum
50% of STI
10% of STI
60% of STI
FY2021 Outcome
51.25%
(or 25.63 out of a possible 50)
93.75%
(or 9.38 out of a possible 10)
58.33%
(or 35 out of a possible 60)
Individual KPIs provide significant relevance to each role in each department, and for FY2021 were assessed as achieving an average of 80%
(or an average of 32 out of a possible 40). Notwithstanding difficult business conditions in FY2021, after assessment of the achievement of
the KPIs above and the Company’s performance during the year, eligible employees were entitled to receive, on average, 67% of their
maximum STIP bonus. The STIP bonuses were paid in cash in July 2021.
STIP starting FY2022
Following a review of the Company’s incentive plans, from 1 July 2021 the Short Term Incentive Plan (STIP) will operate with three levels of
participation for eligible employees, each with a different level of maximum reward:
STIP participation level
(Starting FY2022)
1
2
3
Maximum
% of TFR
30 %
20 %
10 %
The maximum STIP % available has increased from previous years for some eligible employees as they will 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 will nominate a level of participation for each eligible employee after considering factors
such as the eligible employee’s:
a) Role and responsibilities;
b)
Involvement in strategic and operational aspects of management;
c) Ability to be a key driver of the operational parts of the Company’s business; and
d) Ability to influence the Company’s performance.
From 1 July 2021, the CEO and executives who participate in the EIP will not be eligible to participate in the STIP (refer Section H of this
report).
At the Board’s discretion the STIP award may be paid through a combination of cash and/or Company securities.
40
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
H. Executive Incentive Plan (EIP)
Following a review of the Company’s incentive plans, Central will establish an EIP for key executives to align executive performance with
the achievement of key objectives for the Plan Year commencing 1 July 2021 and continuing for subsequent Plan Years commencing 1 July
2022 and 1 July 2023. No further grants will be made to participating executives under the existing LTIP, ESOP and STIP as these plans are
effectively being replaced by the EIP.
As the ESOP Share Options granted in 2019 were granted as incentives for three years, including the year commencing 1 July 2021, 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) 33% is paid at that time (i.e. at the end of the initial 12 month performance period); and
b) 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 entitlement
whereby the Service Rights convert to one share plus an additional number of shares equal in value to the dividends paid 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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
41
REMUNERATION REPORT
(AUDITED)
I. Realised Remuneration
Table 1 identifies the Actual Remuneration received by Senior Executives in respect of the 2021 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 (2021: 11.5 cents per share, 2020: 8.1 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.
Table 1: Realised Remuneration
Current Executive KMP
Leon Devaney
Ross Evans
Damian Galvin4
Duncan Lockhart
Robin Polson
Daniel White
Total Executive KMP
Year
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
Total Fixed
Remuneration1
$
STI (Cash)
$
Other
Benefits2
$
LTI Vested as
Shares3
$
612,061
612,061
500,404
500,404
330,001
289,162
400,001
400,472
335,132
335,132
444,080
444,080
42,231
—
34,527
—
21,449
—
25,999
—
21,783
—
28,864
—
7,635
8,380
7,635
8,380
7,635
7,039
7,635
8,332
7,635
8,380
7,635
8,380
2,621,679
2,581,311
174,853
—
45,810
48,891
66,549
—
28,214
—
—
—
—
—
21,861
—
29,160
—
145,784
—
Total
$
728,476
620,441
570,780
508,784
359,085
296,201
433,635
408,804
386,411
343,512
509,739
452,460
2,988,126
2,630,202
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 Damian Galvin commenced 5 August 2019.
42
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
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
Salary/
Fees
$
Non-
Monetary
Benefits
$
STI1
$
Superannuation
Contributions
$
Termination
Benefits
$
LSL
(Accrued)
$
Rights &
Options2
$
Total
$
Percent of
Remuneration
%
Non-Executive Directors
Stuart Baker
2021
2020
Katherine Hirschfeld
Agu Kantsler3
2021
2020
2021
2020
85,000
86,250
85,833
90,000
78,333
3,111
Michael McCormack4 2021
2020
107,500
—
Former Non-Executive Directors
Julian Fowles5
Wrixon Gasteen6
Martin Kriewaldt7
Sub-total
Executives
Leon Devaney
Ross Evans
Damian Galvin8
Duncan Lockhart
Robin Polson
Daniel White
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
26,667
81,604
64,167
150,000
—
26,667
447,500
437,632
623,324
601,381
499,881
485,955
318,460
277,551
392,139
384,464
318,593
329,546
444,673
430,904
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
42,231
10,941
34,527
8,945
21,449
5,363
25,999
6,708
21,783
5,446
28,864
7,216
7,635
8,380
7,635
8,380
7,635
7,039
7,635
8,332
7,635
8,380
7,635
8,380
8,075
8,194
8,154
8,550
7,442
296
10,212
—
2,533
7,752
6,096
14,250
—
2,533
42,512
41,575
21,694
21,003
21,694
21,003
21,694
19,779
21,694
21,003
21,694
21,003
21,694
21,003
Sub-total
2021
2020
2,597,070 174,853
44,619
2,509,801
Total Remuneration 2021
2020
3,044,570 174,853
44,619
2,947,433
45,810
48,891
45,810
48,891
130,164
124,794
172,676
166,369
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
11,221
12,688
8,690
6,710
4,218
2,920
5,308
4,073
5,870
4,534
8,140
9,180
341,098
219,916
223,072
176,225
130,751
99,694
158,892
120,841
134,477
120,219
123,785
109,385
93,075
94,444
93,987
98,550
85,775
3,407
117,712
—
29,200
89,356
70,263
164,250
—
29,200
490,012
479,207
1,047,203
874,309
795,499
707,218
504,207
412,346
611,667
545,421
510,052
489,128
634,791
586,068
43,447
40,105
1,112,075
846,280
43,447
40,105
1,112,075
846,280
4,103,419
3,614,490
4,593,431
4,093,697
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
37%
26%
32%
26%
30%
25%
30%
23%
31%
26%
24%
20%
31%
25%
28%
22%
1 Short term incentives are unpaid at the end of the financial year. Amounts are shown in respect of the performance period to which they relate. Subsequent to the
end of the 2020 financial year, the Board decided that the 2020 STI was to be awarded as deferred share rights which are expensed over the performance period,
which includes the year to which the bonus relates and the subsequent 3-year vesting period.
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.
3 Agu Kantsler was appointed 15 June 2020.
4 Mr McCormack commenced 1 September 2020
5 Julian Fowles resigned 31 October 2020.
6 Wrix Gasteen resigned 28 November 2020.
7 Martin Kriewaldt resigned 2 September 2019.
8 Damian Galvin commenced 5 August 2019.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 43
REMUNERATION REPORT
(AUDITED)
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
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.
The following factors and assumptions were used in determining the fair value of share rights granted during FY2020:
Grant Date
Expiry Date
09 Aug 20191
23 Aug 20192
13 Sep 20193
07 Nov 20194
13 Sep 2024
30 Jun 2024
08 Dec 2022
12 Nov 2024
Fair Value
Per Right
Exercise
Price
Price of Shares
at Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
$0.155
$0.155
$0.150
$0.119
Nil
Nil
Nil
Nil
$0.155
$0.190
$0.200
$0.170
N/A
98%
N/A
95%
N/A
0.70%
N/A
0.94%
—
—
—
—
1 STIP Rights fully vested on issue – valued at market price at grant date.
2 LTIP Rights for plan year commencing 1 July 2019.
3 Adjustment to number of LTIP Rights for plan year commencing 1 July 2016 – valued at the market price of the known vesting %.
4 LTIP rights issued to L Devaney in respect of the plan year commencing 1 July 2018.
Table 3: Short Term Incentives Awarded
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson
Daniel White
Total
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
Maximum
$
Awarded1
$
Awarded1
%
Forfeited
%
61,206
61,206
50,040
50,040
33,000
33,000
40,000
40,047
33,513
33,513
44,408
44,408
262,167
262,214
42,231
43,762
34,527
35,779
21,449
21,450
25,999
26,832
21,783
21,784
28,864
28,865
174,853
178,472
69%
71%
69%
72%
65%
65%
65%
67%
65%
65%
65%
65%
67%
68%
31%
29%
31%
28%
35%
35%
35%
33%
35%
35%
35%
35%
33%
32%
1 The FY2020 STIP was settled in the form of share rights with a further 3-year vesting period. Nil% had vested at 30 June 2021.
44
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
J. Remuneration Details – Statutory tables (continued)
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
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson
Daniel White
Total
20211
2020
20211
2020
20211
2020
20211
2020
20211
2020
20211
2021
2020
2020
2020
2021
2020
11 Nov 20
07 Nov 19
11 Nov 20
09 Aug 19
11 Nov 20
N/A
11 Nov 20
N/A
11 Nov 20
09 Aug 19
11 Nov 20
24 Jul 20
09 Aug 19
13 Sep 19
23 Aug 19
496,171
1,837,109
405,655
140,845
243,198
—
304,213
—
246,979
94,598
327,269
1,510,476
119,077
123,679
983,204
3,533,961
3,298,512
$0.130
$0.119
$0.130
$0.142
$0.130
N/A
$0.130
N/A
$0.130
$0.142
$0.130
$0.065
$0.142
$0.150
$0.155
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
30 Jun 25
12 Nov 24
30 Jun 25
13 Sep 24
30 Jun 25
N/A
30 Jun 25
N/A
30 Jun 25
13 Sep 24
30 Jun 25
30 Jun 25
13 Sep 24
08 Dec 22
30 Jun 24
1 Represents FY2020 STIP settled as Equity in the form of deferred share rights.
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
LTIP Year
Commencing
STIP Year
Commencing
Number of
Rights
Vested1
Proportion of
LTIP Rights
Vested2
Proportion of
LTIP Rights
Forfeited
2021
2020
2021
2020
2021
2020
2021
2020
2020
2021
2020
1,837,109
890,625
778,854
140,845
603,491
94,598
804,984
736,319
119,077
4,024,438
1,981,464
01 Jul 18
01 Jul 17
01 Jul 18
N/A3
01 Jul 18
N/A3
01 Jul 18
01 Jul 17
N/A3
N/A
N/A
N/A
01 Jul 18
N/A
01 Jul 18
N/A
N/A
01 Jul 18
578,689
—
245,339
140,845
190,099
94,598
253,569
—
119,077
1,267,696
354,520
31.5%
0.0%
31.5%
N/A3
31.5%
N/A3
31.5%
0.0%
N/A3
31.5%
0.0%
68.5%
100.0%
68.5%
N/A3
68.5%
N/A3
68.5%
100.0%
N/A3
68.5%
100.0%
1 The number of rights that vested during the 2021 year 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 Rights issued as part settlement of FY2019 STIP.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 45
REMUNERATION REPORT
(AUDITED)
J. Remuneration Details – Statutory tables (continued)
Table 6: Share Based Compensation – Options Granted to Key Management Personnel during the Year
Number of
Options Granted
Grant Date
Option
Expiry Date
Exercise
Price
Fair Value
at Grant
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson
Total
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
—
5,105,000
—
4,170,025
—
2,750,000
—
3,333,333
—
2,792,758
—
18,151,116
—
07 Nov 19
—
20 Aug 19
—
20 Aug 19
—
20 Aug 19
—
20 Aug 19
—
30 Jun 23
—
30 Jun 23
—
30 Jun 23
—
30 Jun 23
—
30 Jun 23
—
$0.20
—
$0.20
—
$0.20
—
$0.20
—
$0.20
—
$0.087
—
$0.120
—
$0.120
—
$0.120
—
$0.120
The values of Options are calculated at the date of grant using a Black Scholes valuation. The following factors and assumptions were used
in determining the fair value of Options granted to key management personnel during FY2020:
Grant Date
Expiry Date
20 Aug 2019
07 Nov 2019
30 Jun 2023
30 Jun 2023
Fair Value
Per Right
Exercise
Price
Price of
Shares at
Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
$0.120
$0.087
$0.20
$0.20
$0.16
$0.17
78%
78%
0.92%
0.85%
—
—
Share, Rights and Option Holdings of Key Management Personnel
Under the Group’s Long Term Incentive Plans, eligible employees may receive:
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).
Table 7: Vesting profile of Share Rights Holdings of Key Management Personnel
Leon Devaney
Ross Evans
Grant Date Type
7 Nov 2019 Share Rights – LTIP
11 Nov 2020 Deferred Share Rights – STIP3
24 Sep 2018 Share Rights – LTIP
9 May 2019 Share Rights – LTIP
11 Nov 2020 Deferred Share Rights – STIP3
Maximum
Number of
Rights Eligible
for Vesting at
30 June 2021
1,837,109
496,171
642,988
135,866
405,655
Vesting
Date1
30 Jun 2021
30 Jun 2023
30 Jun 2021
30 Jun 2021
30 Jun 2023
Damian Galvin
11 Nov 2020 Deferred Share Rights – STIP3
243,198
30 Jun 2023
Duncan Lockhart
11 Nov 2020 Deferred Share Rights – STIP3
304,213
30 Jun 2023
Robin Polson
Daniel White
Total
24 Sep 2018 Share Rights – LTIP
9 May 2019 Share Rights – LTIP
11 Nov 2020 Deferred Share Rights – STIP3
24 Sep 2018 Share Rights – LTIP
9 May 2019 Share Rights – LTIP
23 Aug 2019 Share Rights – LTIP
24 Jul 2020 Share Rights - LTIP
11 Nov 2020 Deferred Share Rights – STIP3
30 Jun 2021
30 Jun 2021
30 Jun 2023
30 Jun 2021
30 Jun 2021
30 Jun 2022
30 Jun 2023
30 Jun 2023
551,132
52,359
246,979
735,145
69,839
983,204
1,510,476
327,269
8,541,603
Maximum value yet to vest2
FY2021
FY2022
FY2023
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
53,332
—
—
—
32,251
—
—
26,368
15,808
19,774
—
—
16,054
—
—
—
65,454
21,272
53,332
196,981
1 The earliest vesting date under the relevant plan rules. The final vesting date may be subject to retesting periods, subject to Board discretion.
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. 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.
46
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
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 8: Share Rights Holdings of Key Management Personnel
Share Rights
Key Management Personnel
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson
Daniel White
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
(Unvested)
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2,727,734
2,202,158
778,854
778,854
—
N/A
—
N/A
603,491
603,491
2,524,507
2,830,969
6,634,586
6,415,472
496,171
1,837,109
(890,625)
(233,552)
—
(1,077,981)
405,655
140,845
243,198
—
304,213
—
246,979
94,598
—
—
—
—
—
—
—
—
1,837,745
1,225,960
(736,319)
(353,337)
3,533,961
3,298,512
(1,626,944)
(586,889)
—
(140,845)
—
—
—
—
—
(94,598)
—
(1,179,085)
—
(2,492,509)
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
—
—
2,333,280
2,727,734
1,184,509
778,854
243,198
—
304,213
—
850,470
603,491
3,625,933
2,524,507
8,541,603
6,634,586
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 9: Options Holdings of Key Management Personnel
Share Options
Key Management Personnel
Leon Devaney
2021
2020
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson
Total
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
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)
5,105,000
—
4,170,025
—
2,750,000
—
3,333,333
—
2,792,758
—
—
5,105,000
—
4,170,025
—
2,750,000
—
3,333,333
—
2,792,758
—
$0.20
—
$0.20
—
$0.20
—
$0.20
—
$0.20
—
30 Jun 23
—
30 Jun 23
—
30 Jun 23
—
30 Jun 23
—
30 Jun 23
18,151,116
—
—
18,151,116
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
N/A
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
2,792,758
2,792,758
18,151,116
18,151,116
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 47
REMUNERATION REPORT
(AUDITED)
J. Remuneration Details – Statutory tables (continued)
Table 10: 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
Ordinary Shares
Non-Executive Directors
Stuart Baker
2021
2020
Julian Fowles1
Wrixon Gasteen2
2021
2020
2021
2020
Katherine Hirschfeld 2021
2020
Agu Kantsler3
Martin Kriewaldt4
2021
2020
2021
2020
Michael McCormack5 2021
2020
—
—
100,000
—
793,337
293,337
760,850
200,000
—
N/A
N/A
1,100,000
N/A
N/A
Sub-total
2021
2020
1,654,187
1,593,337
Other Key Management Personnel
Leon Devaney
2021
2020
2,606,757
1,053,776
Ross Evans
Damian Galvin6
Duncan Lockhart
Robin Polson
Daniel White
Sub-total
Total KMP
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
140,845
—
141,000
N/A
—
—
94,598
—
2,309,074
1,129,989
5,292,274
2,183,765
6,946,461
3,777,102
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
71,000
N/A
N/A
N/A
N/A
N/A
N/A
—
71,000
—
71,000
—
—
—
100,000
—
500,000
—
560,850
—
—
—
—
—
—
—
1,160,850
—
475,000
—
—
—
70,000
—
—
—
—
—
—
—
545,000
—
1,705,850
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,077,981
—
140,845
—
—
—
—
—
94,598
—
1,179,085
—
2,492,509
—
2,492,509
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Held at
End of
Year
—
—
N/A
100,000
N/A
793,337
760,850
760,850
—
—
N/A
N/A
—
N/A
N/A
N/A
100,000
N/A
793,337
N/A
N/A
N/A
N/A
N/A
N/A
1,100,000
N/A
N/A
893,337
1,100,000
760,850
1,654,187
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
—
—
893,337
1,100,000
2,606,757
2,606,757
140,845
140,845
141,000
141,000
—
—
94,598
94,598
2,309,074
2,309,074
5,292,274
5,292,274
6,053,124
6,946,461
1 Julian Fowles resigned 31 October 2020.
2 Wrixon Gasteen resigned 28 November 2020.
3 Agu Kantsler was appointed 15 June 2020.
4 Martin Kriewaldt resigned 2 September 2019.
5 Michael McCormack was appointed Director on 1 September 2020.
6 Damian Galvin commenced 5 August 2019.
48
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
K. Executive Service Agreements
The details of service agreements of the key management personnel of the Consolidated Entity as of 1 July 2021 are as follows:
Table 11: Key Management Personnel Service Agreements
Name
Position
Leon Devaney
Managing Director & Chief Executive Officer
Ross Evans
Chief Operations Officer
Damian Galvin
Chief Financial Officer
Duncan Lockhart
General Manager Exploration
01 Jul 2022
01 Dec 2022
05 Aug 2022
08 Jul 2022
Jonathan Snape
Chief Commercial Officer
Full time permanent
Daniel White
Group General Counsel & Company Secretary
30 Nov 2021
1 Total Annual Fixed Remuneration includes compulsory superannuation contributions.
2
In certain exceptional circumstances (such as breach or gross misconduct) a shorter notice period applies.
Term of agreement
expires
Total Annual Fixed
Remuneration1
Notice period 2
$625,750
$511,860
$338,050
$409,450
$330,000
$454,410
6 months
6 months
6 months
6 months
3 months
3 months
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 FY2021.
Board Fees (per annum)
Chair
Non-Executive Director
$130,000
$70,000
FY2021 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
21 September 2021
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 49
AUDITOR’S INDEPENDENCE DECLARATION
30 JUNE 2021
Auditor’s Independence Declaration
As lead auditor for the audit of Central Petroleum Limited for the year ended 30 June 2021, 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
21 September 2021
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, www.pwc.com.au
Liability limited by a scheme approved under Professional Standards Legislation.
50
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
FINANCIAL REPORT
CONTENTS
FINANCIAL STATEMENTS
Consolidated Statement of Comprehensive Income ............................................................................... 52
Consolidated Balance Sheet............................................................................................................................... 53
Consolidated Statement of Changes in Equity ......................................................................................... 54
Consolidated Statement of Cash Flows ........................................................................................................ 55
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS ................................................................................56
DIRECTORS’ DECLARATION ................................................................................................................................................ 99
INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS...................................................................................... 100
ASX ADDITIONAL INFORMATION .................................................................................................................................... 105
INTERESTS IN PETROLEUM PERMITS AND PIPELINE LICENCES ...................................................................... 107
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 27. These pages are not part of these financial statements.
The financial statements were authorised for issue by the Directors on 21 September 2021. The Directors have the power to amend and
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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
51
CONSOLIDATED STATEMENT OF COMPREHENSIVE
INCOME
FOR THE YEAR ENDED 30 JUNE 2021
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
Impairment expense
Finance costs
Profit before income tax
Income tax (expense)/credit
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:
NOTE
2
3
4(b)
32(d)
4(a)
4(c)
4(a)
5
2021
$’000
59,827
(28,852)
30,975
155
(7,739)
(2,180)
(1,862)
(924)
(12,503)
—
(5,671)
251
—
251
—
251
251
2020
$’000
65,046
(33,386)
31,660
8,610
(5,277)
(3,668)
(1,937)
(1,110)
(16,257)
(177)
(6,433)
5,411
—
5,411
—
5,411
5,411
Basic earnings per share (cents)
Diluted earnings per share (cents)
23
23
0.03
0.03
0.75
0.75
The accompanying notes form part of these financial statements.
52
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
CONSOLIDATED BALANCE SHEET
AS AT 30 JUNE 2021
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
NOTE
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
174,172
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
2020
$’000
25,918
6,774
2,581
—
35,273
107,845
1,059
8,722
312
2,656
3,906
124,500
159,773
5,287
10,891
6,964
608
4,774
—
28,524
22,964
63,809
618
42,276
129,667
158,191
1,582
197,776
29,094
(223,181)
197,776
27,238
(223,432)
3,689
1,582
The accompanying notes form part of these financial statements.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
53
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEAR ENDED 30 JUNE 2021
Balance at 1 July 2019
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
Contributed
Equity
$’000
Reserves
$’000
Accumulated
Losses
$’000
197,776
25,310
(228,843)
—
—
—
—
—
—
—
—
—
1,937
(9)
1,928
5,411
—
5,411
—
—
—
Balance at 30 June 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
$’000
(5,757)
5,411
—
5,411
1,937
(9)
1,928
1,582
251
—
251
1,862
(6)
1,856
3,689
The accompanying notes form part of these financial statements.
54
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED 30 JUNE 2021
NOTE
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 property, plant and equipment
Proceeds and deposits for the disposal of exploration permits
(Lodgement)/redemption of security deposits and bonds
Net cash (outflow)/inflow 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 increase in cash and cash equivalents
29(b)
29(b)
Cash and cash equivalents at the beginning of the financial year
Cash and cash equivalents at the end of the financial year
7
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
2020
$’000
62,945
172
6
(133)
(5,089)
(3,142)
(39,032)
15,727
(3,224)
76
7,713
115
4,680
(10)
(11,501)
(236)
(548)
(12,295)
8,112
17,806
25,918
The accompanying notes form part of these financial statements.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
55
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
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.
The Group recorded a net profit for the year of $251,000, had a net positive cash flow from operations of $24,136,000 and had an overall
net current asset position at 30 June 2021 of $8,253,000, inclusive of assets held for sale and liabilities directly associated with those
assets. The net current assets include $5,244,000 of deferred revenue liabilities which will be settled via the physical delivery of gas rather
than as any cash payment to the customer. The Board and management monitor the Group’s cash flow requirements to ensure it has
sufficient funds to meet its contractual commitments and adjusts its spending, particularly with respect to discretionary exploration activity
and corporate expenditures.
Supported by the cash assets at 30 June 2021 of $37,159,000, and expected operating cashflows, the Group forecasts that over at least the
next 12 months, it will have sufficient funds to meet its commitments and continue to pay its debts as and when they fall due. To date the
Group has been successful in funding new projects through a combination of borrowings, gas presales, farmouts and equity from new and
existing shareholders. The partial asset sale, which is expected to complete on 1 October 2021, includes deferred consideration of
$40,000,000 which will fund Central’s share of selected future capital exploration and development costs in those areas for at least the
next 12 months.
Current borrowings of $36,000,000 includes $29,000,000 to be repaid from the proceeds of the partial asset sale upon completion. This
would otherwise have been classified as a non-current borrowing, but due to the asset sale, as at 30 June 2021 there is not an
unconditional right to defer settlement of this amount for at least 12 months and it has been classified as a current borrowing. If the
transaction does not complete, the $29,000,000 would revert to being payable on 30 September 2022. Central and its secured lender have
agreed to the necessary revisions to the financing arrangements to accommodate the partial asset sale and loan prepayment. Management
and the Board are considering various refinancing / maturity extension options and are confident that new financing arrangements will be
in place before expiry of the existing loan facility in September 2022.
Accordingly, the Directors believe the going concern assumption is appropriate.
(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 2020 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.
56
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(a) Basis of Preparation (continued)
(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.
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. 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
Other non-financial assets, including property, plant and equipment and goodwill are 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.
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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
57
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(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.
(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 34.
(c) Segment Reporting
Operating segments are reported in Note 24 in a manner consistent with the internal reporting provided to the chief operating decision
maker. 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.
58
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(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.
(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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
59
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(g) Income Tax (continued)
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.
60
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(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. 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.
(n) Property, Plant and Equipment – Development and Production Assets
(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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
61
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(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
(p) Exploration Expenditure
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.
62
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(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.
(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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
63
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(t) Employee Benefits (continued)
(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
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.
(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.
64
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(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:
•
•
•
•
•
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.
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.
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.
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
2020:
• AASB 2018-7 Amendments to Australian Accounting Standards – Definition of Material [AASB 101 and AASB 108]
• AASB 2018-6 Amendments to Australian Accounting Standards – Definition of a Business [AASB 3]
• AASB 2019-3 Amendments to Australian Accounting Standards – Interest Rate Benchmark Reform [AASB 9, AASB 139 and AASB 7]
• AASB 2019-5 Amendments to Australian Accounting Standards – Disclosure of the Effect of New IFRS Standards Not Yet issued in
Australia [AASB 1054]
• Conceptual Framework for Financial Reporting and AASB 2019-1 Amendments to Australian Accounting Standards – References to the
Conceptual Framework.
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.
The IFRS Interpretations Committee (IFRIC) issued agenda decisions relating to the accounting for SaaS arrangements. The Group has
implemented this guidance and determined that there is no material impact as a result of the change in accounting policy.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
65
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
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
2021
$’000
54,355
5,472
59,827
2020
$’000
58,960
6,086
65,046
Revenue relating to contracts with major customers is disclosed in Note 24 – Segment Reporting.
(b) Contract Liabilities
Deferred Revenue – take-or-pay contracts1
Deferred Revenue – other gas sales contracts2
2021
Non-
current
$’000
Total
$’000
Current
$’000
2020
Non-
current
$’000
Total
$’000
11,017
12,374
4,680
8,567
2,714
8,177
18,977
21,691
3,987
12,164
Current
$’000
1,357
3,887
Total contract liabilities
5,244
15,697
20,941
10,891
22,964
33,855
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.
During the year the Group secured a new Gas Supply Agreement to supply 3.5 PJ of gas over calendar years 2022 and 2023. The sale
proceeds were pre-paid in full during the year and have been included as deferred revenue. Other movements in contract liabilities during
the year included $7,908,000 (2020: $7,693,000) recognised as revenue from amounts included in contract liabilities at the beginning of
the year, finance charges, and new take or pay amounts accrued. Deferred revenue liabilities of $20,941,000 associated with available for
sale assets as at 30 June 2021 have been reclassified as a current liability “Liabilities directly associated with assets classified as held for
sale” (refer Note 10).
3. OTHER INCOME
Interest
Profit on disposal of exploration permits (a)
Profit on disposal of inventory and other assets
Other income
Total other income
2021
$’000
76
–
79
—
155
2020
$’000
152
8,393
60
5
8,610
(a)
In January 2020 the Consolidated Entity received a Sole Funding Commitment Termination Fee of $7,713,000 from its joint venture partner in ATP2031.
Under the terms of the Joint Venture Agreement this amount represented the balance of consideration payable in respect of the transfer of a 50%
interest in the Permit to the joint venture partner. The balance of $680,000 in the 2020 year relates to the profit recorded on disposal of interests in
Northern Territory exploration permits EP93, EP97 and EP107 following government approval and registration of the transfer.
66
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
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
Impairment expense
Finance costs
Interest and fees on debt facilities
Interest on lease liabilities
Interest on other financial liabilities
Revaluation of financial liabilities
Amortisation of deferred finance costs
Accretion charges
Total finance costs
(b) Government Grants
NOTE
11
11
11
11
12(b)
14
12(b)
4(c)
12(b)
2021
$’000
332
6,942
4,577
40
514
2020
$’000
350
9,945
5,353
40
492
12,405
16,180
98
9
–
4,074
70
—
—
36
1,491
5,671
77
39
177
5,191
102
56
(2)
575
511
6,433
In response to the impacts of COVID-19 the Australian Government made the JobKeeper support package available to eligible affected
businesses. The Company recognised subsidies totalling $891,000 (2020: $759,000) against net employee costs.
In addition, $218,000 (2020: Nil) was received from the Northern Territory Government as training incentives for operational staff and
recognised against net employee costs.
(c)
Impairment of Exploration Assets
In the 2020 financial year the Consolidated Entity fully impaired the assets relating to exploration tenement EP105 and application area
EP(A)130 amounting to $177,000. The impairment was based on the limited likelihood of future work being undertaken in those areas.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
67
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
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.
2021
$’000
2020
$’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% (2020: 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
—
—
—
251
75
18
559
10
662
(662)
—
2
(2)
—
—
—
—
5,411
1,623
180
581
8
2,392
(2,392)
—
45
(45)
—
Unutilised tax losses for which no deferred tax asset has been recognised
Potential tax benefit at 30%
139,107
41,732
126,635
37,991
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.
68
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
5.
INCOME TAX (CONTINUED)
(e) Deferred tax assets and liabilities
2021
$’000
2020
$’000
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
Net deferred tax assets not recognised
Movements in deferred tax assets
Opening balance at 1 July
Credited/(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
Accrued income
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
Charged/(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 (2020: Nil).
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
14,171
1,845
425
56
52,267
68,764
(14,276)
54,488
14,454
(178)
14,276
11,299
2,977
14,276
3
2,503
11,770
14,276
(14,276)
—
14,454
(178)
14,276
14,097
179
14,276
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 69
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
6. REMUNERATION OF AUDITORS
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
2021
$
2020
$
194,538
213,265
9,129
26,864
35,993
14,657
26,092
40,749
230,531
254,014
2021
$000
37,165
36,281
878
37,159
6
37,165
2020
$000
25,918
25,252
666
25,918
—
25,918
(a) $11,112,000 of this balance relates to cash held with Macquarie Bank Limited to be used for allowable purposes under the Facility
Agreement (2020: $5,486,000), 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 receivables
Accrued income (a)
Other receivables
Prepayments
2021
$’000
—
5,628
456
1,027
7,111
2020
$’000
476
4,698
279
1,321
6,774
(a) Accrued income relates to the revenue recognition of hydrocarbon volumes delivered to respective customers but not yet invoiced.
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)).
70
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
9.
INVENTORIES
Crude oil and natural gas
Spare parts and consumables
Drilling materials and supplies at cost
2021
$’000
28
1,035
558
1,621
2020
$’000
61
1,975
545
2,581
10. ASSETS AND LIABILITIES CLASSIFIED AS HELD FOR SALE
On 25 May 2021, the Group announced it had entered into a binding agreement with New Zealand Oil and Gas Limited (“NZOG”) and Cue
Energy Resources Limited (“Cue”) to sell 50% of the Group’s current working interest in its Amadeus Basin Producing Assets.
The assets being sold consist of 50% of the Group’s interest in its producing assets in the Northern Territory, namely Mereenie Oil and Gas
Field (OL 4/5), Palm Valley Gas Field (OL 3), and Dingo Gas Field (L7).
At 30 June 2021, the transac�on was subject to various regulatory approvals. Comple�on is expected to occur on 1 October 2021. At 30
June 2021, assets of $57,968,000 were classified as held for sale and liabili�es of $39,436,000 were associated with these assets. The major
classes of assets comprising the sale interests classified as held for sale and associated liabili�es are 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
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
71
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
37,070
107,845
11. PROPERTY, PLANT AND EQUIPMENT
Freehold Land
and Buildings
$’000
Producing
Assets
$’000
Plant and
Equipment
$’000
Year ended 30 June 2020
Opening net book amount
Additions
Changes to rehabilitation estimates
Disposals and write offs
Depreciation charge
Closing net book amount
At 30 June 2020
Cost
Accumulated depreciation
Net book amount
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
2,529
—
—
—
(350)
2,179
3,869
(1,690)
2,179
2,179
—
—
—
(332)
(917)
930
1,952
(1,022)
930
81,046
264
(2,769)
—
(9,945)
68,596
98,384
(29,788)
68,596
68,596
5,937
536
—
(6,942)
(34,254)
33,873
53,381
(19,508)
33,873
39,900
2,593
(5)
(25)
(5,393)
37,070
67,800
(30,730)
37,070
5,855
4
(4)
(4,617)
(19,123)
19,185
40,211
(21,026)
19,185
At 30 June 2021, $3,015,000 of property plant and equipment balances relates to assets under construction and is not subject to
depreciation until complete (2020: $1,908,000).
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
72
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
2021
$’000
1,211
244
1,455
517
992
1,509
Total
$’000
123,475
2,857
(2,774)
(25)
(15,688)
107,845
170,053
(62,208)
107,845
11,792
540
(4)
(11,891)
(54,294)
53,988
95,544
(41,556)
53,988
2020
$’000
673
386
1,059
608
618
1,226
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
12. LEASES (CONTINUED)
(a) Amounts recognised in the balance sheet (continued)
Additions to the right-of-use assets during the 2021 financial year were $1,055,000 (2020: $159,000) and $145,000 was reclassified as held
for sale – refer Note 10 (2020: 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
Expense related to short term leases included in cost of sales and general and
administrative expenses
The total cash outflow for leases in 2021 was $691,000 (2020: $650,0000).
2021
$’000
2020
$’000
359
155
514
70
9
359
133
492
102
39
(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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
73
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
12. LEASES (CONTINUED)
(c) The Group’s leasing activities and how they are accounted for (continued)
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.
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.
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
Impairment expense (Note 4(c))
Reclassified as held for sale (Note 10)
Balance at the end of the year
2021
$’000
8,397
8,722
–
(325)
8,397
2020
$’000
8,722
8,899
(177)
—
8,722
74
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
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
15. OTHER FINANCIAL ASSETS
Non-Current
Security bonds on exploration permits and rental properties
2021
$’000
2020
$’000
788
(476)
312
312
105
(98)
(17)
302
848
(546)
302
512
(399)
113
113
276
(77)
—
312
788
(476)
312
2021
$’000
4,218
2020
$’000
2,656
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.
16. GOODWILL
Goodwill arising from business combinations
Movement
2021
$’000
1,953
2020
$’000
3,906
As 30 June 2021 $1,953,000 of goodwill was reclassified as held for sale (refer Note 10).
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 current equity interests in its Amadeus Basin producing assets. The assets being disposed
represent 50% of the total cash generating unit upon which Central assesses recoverable amount each year.
Central will receive an upfront cash payment of $29,000,000 and deferred consideration of $40,000,000 to fund Central’s share of selected
near-term development, appraisal and exploration activities in the producing areas. In addition, NZOG and Cue will assume 50% of
Central’s relevant liabilities relating to gas which has previously been paid for but not delivered under pre-sale or take-or-pay
arrangements with a book value of $20,941,000 at 30 June 2021.
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 2021.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
75
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
16. GOODWILL (CONTINUED)
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.
The value of the transaction consideration (grossed up for the value of liabilities assumed by the purchaser) substantially exceeds the
carrying value of the assets being sold 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 2021.
17. TRADE AND OTHER PAYABLES
Current
Trade payables
Other payables
Accruals
2021
$’000
5,312
31
5,148
10,491
2020
$’000
2,026
11
3,250
5,287
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.
18. BORROWINGS
(a)
Current1
Debt facilities
(b)
Non-current1
Debt facilities
Details regarding interest bearing liabilities are contained in Note 33(e).
19. PROVISIONS
2021
$’000
36,000
2020
$’000
6,964
30,809
63,809
Employee entitlements (a)
Restoration and rehabilitation (b)
Joint Venture production over-lift (c)
2021
Current Non-Current
$’000
$’000
3,184
—
734
3,918
1,084
23,466
2,829
27,379
Total
$’000
4,268
23,466
3,563
31,297
2020
Current Non-Current
$’000
$’000
3,942
120
712
4,774
828
37,988
3,460
42,276
Total
$’000
4,770
38,108
4,172
47,050
(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 $635,000 (2020: $788,000).
(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.
76
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
19. PROVISIONS (CONTINUED)
Movements in Provisions
Movements in each class of provision during the financial year are set out below:
2021
Carrying amount at start of year
Change in provision charged to property, plant and
equipment
Additional provisions charged to profit or loss
Unwinding of discount
Amounts used during the year
Reclassified as held for sale (Note 10)
Carrying amount at end of year
20. CONTRIBUTED EQUITY
(a) Share capital
Employee
Entitlements
$’000
Restoration &
Rehabilitation
$’000
Joint Venture
Production
Over-Lift
$’000
38,108
4,172
4,770
—
2,404
—
(2,906)
—
4,268
540
1,371
314
(118)
(16,749)
23,466
—
123
—
(732)
—
Total
$’000
47,050
540
3,898
314
(3,756)
(16,749)
3,563
31,297
2021
$’000
2020
$’000
724,093,661 fully paid ordinary shares (2020: 723,288,869)
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
2021
Number of Shares
2020
Number of Shares
Balance at start of year
Shares issued under Employee Incentive Plans
723,288,869
804,792
713,355,716
9,933,153
Balance at end of year
724,093,661
723,288,869
2021
$’000
197,776
—
197,776
2020
$’000
197,776
—
197,776
(b) Share Options
The following table shows the movement in options over ordinary shares during the year:
Class
Expiry Date
Exercise
Price
Balance at
Start of Year
Issued
During the
Year
Lapsed
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
—
—
—
—
—
—
18,151,116
18,151,116
(c) Share rights under the Long Term Incentive Plan
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.
Final vesting percentages are determined by 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.
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 or a percentage of the employee’s base salary, divided by the volume weighted
average share price at the start of the plan year. The table below sets out the maximum number of share rights subject to performance
hurdles outstanding at year end and movements for the year.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
77
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
20. CONTRIBUTED EQUITY (CONTINUED)
Class
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee Deferred Share rights1
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
05 Jan 2021
1 Jul 2015
7,305
08 Dec 2022
1 Jul 2016
579,386
—
—
—
—
(7,305)
(579,386)
—
—
03 Oct 2022
1 Jul 2017
4,601,645
20,271
(4,390,117)
(218,101)
13,698
23 May 2023
1 Jul 2017
16,868
28 Jun 2023
1 Jul 2017
135,920
22 May 2024
1 Jul 2018
6,444,398
12 Nov 2024
1 Jul 2018
1,837,109
—
—
—
—
(16,868)
(135,920)
(187,418)
—
30 Jun 2024
1 Jul 2019
7,353,175
30,545
(561,314)
—
—
—
—
—
—
—
—
—
6,256,980
1,837,109
6,822,406
3,692,054
9,917,120
Employee LTIP rights
30 Jun 2025
1 Jul 2020
30 Jun 2025
1 Jul 2019
—
—
3,692,054
9,917,120
—
—
Total
20,975,806
13,659,990
(5,291,637)
(804,792) 28,539,367
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.
The rights do not entitle the holders to participate in any share issue of the Company or any other entity.
(d) Capital risk management
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. This is monitored through the use of cash flow forecasts.
In order to satisfy the capital requirements of the Group, the Company may issue new shares or other equity instruments.
21. RESERVES
Share options reserve
Movements:
Balance at start of year
Share based payment costs (a)
Transaction costs
Balance at end of year
2021
$’000
29,094
27,238
1,862
(6)
29,094
2020
$’000
27,238
25,310
1,937
(9)
27,238
(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
2021
$’000
(223,432)
251
(223,181)
2020
$’000
(228,843)
5,411
(223,432)
78
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
23. EARNINGS/(LOSS) PER SHARE
(a)
Basic earnings per share (cents)
(b)
Diluted earnings per share (cents)
(c)
Profit used in earnings per share calculation
Profit attributed to ordinary equity holders ($’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
2021
0.03
0.03
2020
0.75
0.75
251
5,411
723,619,673
720,898,329
17,469,319
1,057,114
741,088,992
721,955,443
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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
79
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
24. SEGMENT REPORTING (CONTINUED)
(e) Performance monitoring and evaluation (continued)
2021
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
Producing
Assets
2021
$’000
Exploration
Assets
2021
$’000
Unallocated
Items
2021
$’000
Consolidation
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
—
—
—
—
—
70
—
—
—
70
—
(6,727)
—
(12)
(6,669)
—
(6,669)
—
—
—
—
—
2
(1,862)
(924)
(2,180)
(4,964)
(720)
—
55
(373)
(6,002)
—
(6,002)
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
133,492
10,264
30,416
174,172
Segment liabilities
(150,774)
(5,462)
(14,247)
(170,483)
Capital expenditure
Property, plant and equipment
Intangibles
Total capital expenditure
11,703
5
11,708
—
—
—
89
99
188
11,792
104
11,896
1 Non-cash item.
2 EBITDAX is earnings before interest, taxation, depreciation, amortisation, and exploration expense.
80
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
24. SEGMENT REPORTING (CONTINUED)
(e) Performance monitoring and evaluation (continued)
2020
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
Impairment expense1
Profit / (loss) before income tax
Taxes
Profit / (loss) for the year
Producing
Assets
2020
$’000
Exploration
Assets
2020
$’000
Unallocated
Items
2020
$’000
Consolidation
2020
$’000
58,960
6,086
65,046
(33,386)
31,660
9
—
—
—
31,669
(15,528)
(678)
47
(5,860)
—
9,650
—
9,650
—
—
—
—
—
8,437
—
—
—
8,437
—
(4,599)
–
(18)
(177)
3,643
—
3,643
—
—
—
—
—
12
(1,937)
(266)
(4,512)
(6,703)
(729)
—
105
(555)
—
(7,882)
—
(7,882)
58,960
6,086
65,046
(33,386)
31,660
8,458
(1,937)
(266)
(4,512)
33,403
(16,257)
(5,277)
152
(6,433)
(177)
5,411
—
5,411
Segment assets
132,817
10,958
15,998
159,773
Segment liabilities
(141,530)
(3,301)
(13,360)
(158,191)
Capital expenditure
Property, plant and equipment
Intangibles
Total capital expenditure
2,763
23
2,786
—
—
—
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.
94
253
347
2021
$’000
59,827
2,857
276
3,133
2020
$’000
65,046
70,313
124,500
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
81
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
24. SEGMENT REPORTING (CONTINUED)
(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
2021
$’000
20,028
14,597
10,468
7,803
—
% of Sales
Revenue
33%
24%
17%
13%
—
2020
$’000
18,918
12,712
9,629
8,504
7,649
% of Sales
Revenue
29%
20%
15%
13%
12%
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)/Profit for the year
Total comprehensive (loss)/profit
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)
2020
$’000
21,983
23,797
45,780
(21,749)
(1,372)
(23,121)
22,659
197,776
27,238
(202,355)
22,659
10,829
10,829
(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.
(c) Commitments of the Parent Entity
Operating lease commitments of the Parent Entity are set out in Note 31(c).
82
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
26. RELATED PARTY TRANSACTIONS
(a) Parent Entity
The Parent Entity is Central Petroleum Limited.
(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 35 to 49.
Equity Holding
2021
%
2020
%
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
2021
$
3,265,233
172,676
43,447
1,112,075
2020
$
3,040,943
166,369
40,105
846,280
4,593,431
4,093,697
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
83
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
27. DEED OF CROSS GUARANTEE
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.
The parties to the deed of cross guarantee are:
Central Petroleum Limited
Central Petroleum Projects Pty Ltd
•
•
• Ordiv Petroleum Pty Ltd
•
•
•
•
•
Central Petroleum (NT) Pty Ltd
Central Petroleum Mereenie Pty Ltd
Central Petroleum WS (NO 2) Pty Ltd
Central Petroleum Eastern Pty Ltd
Central Petroleum Services Pty Ltd
Helium Australia Pty Ltd
Frontier Oil & Gas Pty Ltd
Central Geothermal Pty Ltd
Central Petroleum PVD Pty Ltd
• Merlin Energy 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 2021.
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
Impairment expense
Loss before income tax
Income tax credit
(Loss)/Profit for the year
Other comprehensive (loss)/profit for the year, net of tax
Total comprehensive (loss)/profit for the year
Accumulated losses at the beginning of the financial year
AASB 16 Lease accounting adjustments
(Loss)/Profit for the year
Accumulated losses at the end of the financial year
84
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
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)
(213,992)
—
(4,052)
(218,044)
2020
$’000
26,505
(11,389)
15,116
8,604
(1,937)
413
(8,441)
(4,512)
(5,234)
(4,367)
(177)
(535)
1,570
1,035
—
1,035
(214,888)
(139)
1,035
(213,992)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
27. DEED OF CROSS GUARANTEE (CONTINUED)
(b) Consolidated balance sheet
Set out below is a consolidated balance sheet of the closed group as at 30 June.
2021
$’000
2020
$’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
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
25,652
3,941
1,172
—
30,765
55,797
833
8,722
286
2,110
5,456
3,906
77,110
107,875
13,800
1,983
3,846
562
4,062
—
24,253
18,537
35,389
431
18,243
72,600
96,853
11,022
197,776
27,238
(213,992)
11,022
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
85
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
28. RECONCILIATION OF PROFIT AFTER INCOME TAX TO NET CASH
FLOWS FROM OPERATING ACTIVITIES
Profit after income tax
Adjustments for:
Depreciation and amortisation
Impairment expense
Profit on disposal of assets
Profit on disposal of exploration permits
Share-based payments
Financing costs and interest (non-cash)
Changes in assets and liabilities relating to operating activities:
(Increase)/Decrease in trade and other receivables
(Increase)/Decrease in inventories
Increase/(Decrease) in trade and other payables
Increase/(Decrease) in deferred revenue
Increase in provisions
Net cash inflow from operations
29. CASH FLOW INFORMATION
(a)
Non-cash investing and financing activities
2021
$’000
251
12,503
—
(6)
—
1,862
1,747
(515)
(93)
1,395
6,850
142
24,136
2020
$’000
5,411
16,257
177
(51)
(8,393)
1,937
834
2,290
138
(481)
(4,275)
1,883
15,727
In 2020, non-cash interest relating to Other Financial Liabilities amounted to $56,000 and non-cash revaluation credits amounted to
$2,000. Refer Note 4(a).
During the 2020 year an amount of $15,819,000 was transferred to Deferred Revenue from Other Financial Liabilities. This was due to a
novation of rights and obligations under the MBL Gas Sale and Prepayment Agreement from MBL to a third party in respect of the Second
and Third Contract Years, reflecting the removal of the cash settlement option.
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
86
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
2021
$’000
37,165
(36,543)
(31,925)
(31,303)
37,165
(1,659)
(66,809)
(31,303)
2020
$’000
25,918
(7,572)
(64,427)
(46,081)
25,918
(1,226)
(70,773)
(46,081)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
29. CASH FLOW INFORMATION (CONTINUED)
(b) Net debt reconciliation (continued)
Movement in Net Debt
Other Assets
Liabilities from Financing Activities
Cash
$’000
17,806
8,112
—
—
25,918
11,247
—
—
37,165
Borrowings
$’000
(81,730)
11,501
—
(544)
(70,773)
4,000
—
(36)
Leases
$’000
(1,615)
548
(159)
—
Total
$’000
(65,539)
20,161
(159)
(544)
(1,226)
(46,081)
622
(1,055)
—
15,869
(1,055)
(36)
(66,809)
(1,659)
(31,303)
Net debt 1 July 2019
Cash flows
Acquisition - leases
Other non-cash movements
Net debt 30 June 2020
Cash flows
Acquisition - leases
Other non-cash movements
Net debt 30 June 2021
30. CONTINGENCIES
(a) Contingent liabilities
(i)
Exploration Permits
The Consolidated Entity had contingent liabilities at 30 June 2021 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 (2020: $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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
87
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
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
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
2021
$’000
2020
$’000
3,159
3,159
475
475
11,742
56,400
—
68,142
10,578
55,087
8,100
73,765
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.
(c) Operating lease commitments
The Consolidated Entity has non-cancellable operating leases.
Commitments for minimum lease payments in relation to non-cancellable operating leases not recognised as a lease liability on the balance
sheet are as follows:
Within one year
2021
$’000
—
—
2020
$’000
10
10
88
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
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
2021
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
$0.20
$0.20
$0.120
$0.087
$0.111
—
—
—
—
2020
20 Aug 2019
07 Nov 2019
Totals
30 Jun 20231
30 Jun 2023
Weighted average exercise
price
—
—
—
13,046,116
5,105,000
$0.20
$0.20
18,151,116
$0.120
$0.087
$0.111
—
—
—
—
—
—
—
13,046,116
5,105,000
18,151,116
$0.20
13,046,116
5,105,000
18,151,116
—
—
—
—
—
—
—
—
—
$0.20
—
$0.20
1 On 7 November 2019 the expiry date of these options was changed from 30 June 2032 to 30 June 2023. The modification resulted in a lower fair value than the
original valuation. Under the requirements of AASB 2 the effect of any decrease in fair value is not recognised.
The weighted average remaining contractual life at 30 June 2021 was 2-years (2020:3-years). The values of Executive Options are
calculated at the date of grant using a Black Scholes valuation. The following factors and assumptions were used in determining the fair
value of options granted to executives during the 2020 year:
Grant Date
Expiry Date
2020
20 Aug 2019 30 Jun 2023
07 Nov 2019 30 Jun 2023
Fair Value
Per Right
Exercise
Price
Price of Shares
at Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
$0.120
$0.087
$0.20
$0.20
$0.16
$0.17
78%
78%
0.92%
0.85%
—
—
(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. The following rights were issued
during the year:
Grant Date
Plan Year End
2021
11 Nov 2020 30 Jun20201
2020
09 Aug 2019 30 Jun 20192
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
—
3,311,771
$0.155
(3,311,771)
—
—
3,692,054
—
The weighted average fair value of share rights issued under the Short Term Incentive Plan during the year was $0.130 (2020: $0.142).
1 Share rights in respect of the performance period ended 30 June 2020 have a deferred vesting date of 30 June 2023.
2 Share rights in respect of the performance period ended 30 June 2019 vested immediately on issue.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
89
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
32. SHARE BASED PAYMENTS (CONTINUED)
(c) Rights to shares — Long Term Incentive Plan
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 until the end of the performance
period which is 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.
Final vesting percentages 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.
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.
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:
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
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
The weighted average fair value of share rights granted under the Long Term Incentive Plan during the year was $0.084 (2020: $0.15). The
weighted average remaining contractual life of outstanding share rights at the end of the year was 3.5 years (2020: 3.6 years).
The fair values of deferred share rights granted are valued using methodology that takes into account market and peer performance
hurdles. The value of share 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.
90
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
32. SHARE BASED PAYMENTS (CONTINUED)
(c) Rights to shares — Long Term Incentive Plan (continued)
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
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
—
—
LTIP Rights for the plan year commencing 1 July 2020.
Deferred share rights issued in lieu of cash under the short term incentive plan for the year commencing 1 July 2019.
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
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
01 Sep 2017 30 Jun 2017
24 Jan 2017 30 Jun 2017
16 Nov 2016 30 Jun 2017
20 Oct 2016 30 Jun 2017
20 Oct 2016 30 Jun 2017
09 Nov 2015 30 Jun 2016
—
—
—
—
791,808
49,321
7,816
5,784,715
366,711
639
135,920
6,562
10,306
5,198,232
232,990
70,000
25,324
2,631,108
6,607,956
338,442
6,666
1,837,109
627,417
398,520
7,405,740
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
$0.119
$0.150
$0.089
$0.155
$0.101
$0.111
$0.150
$0.087
$0.120
$0.067
$0.102
$0.126
$0.175
$0.081
$0.115
$0.082
$0.190
$0.151
$0.106
$0.135
$0.184
—
(430,073)
—
—
—
—
—
—
—
—
—
—
—
—
—
(52,500)
(25,324)
(1,518,532)
(4,275,334)
(319,619)
—
—
(146,644)
(49,812)
(401,273)
(23,266)
—
(5,250)
(482,686)
(44,771)
—
—
—
—
(797,809)
(31,768)
(17,500)
—
(1,112,576)
(1,815,047)
(7,712)
—
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
Totals
22,264,516
10,268,786
(6,621,382)
(4,936,114)
20,975,806
The following factors and assumptions were used in determining the fair value of share rights granted during FY2020:
Grant Date Expiry Date
09 Aug 20191 13 Sep 2024
23 Aug 20192 30 Jun 2024
13 Sep 20193 08 Dec 2022
07 Nov 20194 12 Nov 2024
Fair Value
Per Right
Exercise
Price
Price of Shares
at Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
$0.155
$0.155
$0.150
$0.119
Nil
Nil
Nil
Nil
$0.155
$0.190
$0.200
$0.170
N/A
98%
N/A
95%
N/A
0.70%
N/A
0.94%
—
—
—
—
1 STIP Rights fully vested on issue – valued at market price at grant date.
2 LTIP Rights for plan year commencing 1 July 2019.
3 Adjustment to number of LTIP Rights for plan year commencing 1 July 2016 – valued at the market price of the known vesting %.
4 LTIP rights issued to L Devaney in respect of the plan year commencing 1 July 2018
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
91
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
32. SHARE BASED PAYMENTS (CONTINUED)
(d) Expenses arising from share-based payment transactions
Total expenses arising from share-based transactions recognised during the year were:
Share Rights issued to employees
33. FINANCIAL RISK MANAGEMENT
2021
$
2020
$
1,862,072
1,937,011
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.
(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 2021 is nil (2020: nil), no loss allowance provision has been recorded at 30 June 2021 (2020: 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
2021
$’000
2020
$’000
2021
$’000
2020
$’000
6,084
5,453
6,084
5,453
—
—
—
—
The receivables at 30 June 2021 relate predominantly to oil and gas sales which have all been received subsequent to year end.
Credit risk also arises in relation to financial guarantees given by the Parent Entity and other non-borrowing Group entities to certain
parties in respect of borrowings by other Group entities (refer Note 25(b)). Such guarantees are only provided in exceptional circumstances
and are subject to specific Board approval.
92
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
33. FINANCIAL RISK MANAGEMENT (CONTINUED)
(b) Liquidity Risk
Prudent liquidity risk management implies maintaining sufficient cash and marketable securities and the availability of funding.
Management monitors rolling forecasts of the Group’s liquidity reserve (comprising the undrawn borrowing facilities below) and cash and
cash equivalents (Note 7) based on expected cash flows. This is carried out at the Group level in accordance with practice and limits set by
the Board of Directors. In addition, the Group’s liquidity management policy involves projecting cash flows, monitoring balance sheet
liquidity ratios against internal and external regulatory requirements and maintaining debt financing plans.
The Group manages its exposure to key financial risks primarily through supervision by the Audit and Financial Risk Committee. The
primary function of this Committee is to assist the Board to fulfil its responsibility to ensure that the Group’s internal control framework is
effective and efficient.
The following are the contractual maturities of financial assets and liabilities:
2021 ($’000)
Financial Assets
Cash and cash equivalents
Trade and other receivables
Other financial assets
Financial Liabilities
Trade and other payables
Interest bearing liabilities
2020 ($’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
37,159
6,084
—
43,243
(10,491)
(33,245)
(43,736)
—
—
—
—
—
—
—
4,218
4,218
—
(5,221)
(32,271)
(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)
≤ 6 Months
6–12 Months
1–5 Years
≥ 5 Years
Contractual
Cash Flow
Carrying
Amount
25,918
5,453
—
31,371
—
—
—
—
—
—
2,656
2,656
(5,073)
(5,355)
(214)
(6,227)
—
(64,837)
(10,428)
(6,441)
(64,837)
—
—
—
—
—
(143)
(143)
25,918
5,453
2,656
34,027
(5,287)
(76,562)
(81,849)
25,918
5,453
2,656
34,027
(5,287)
(71,999)
(77,286)
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
93
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
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
2021
%
2020
%
2021
$’000
2020
$’000
2021
$’000
2020
$’000
2021
$’000
2020
$’000
2021
$’000
2020
$’000
Financial Assets:
Cash and cash equivalents
Trade and other receivables
Other financial assets
Total Financial Assets
Financial Liabilities:
Trade and other payables
Interest bearing liabilities
Total Financial Liabilities
Net Financial Assets /
(Liabilities)
0.3
—
0.0
—
5.6
Interest Rate Sensitivity
0.3
—
0.2
37,159
—
—
25,918
—
—
37,159
25,918
—
—
908
908
—
—
1,083
—
6,084
3,310
—
5,453
1,573
37,159
6,084
4,218
25,918
5,453
2,656
1,083
9,394
7,026
47,461
34,027
—
5.6
—
(66,809)
—
(70,773)
—
(1,509)
—
(1,226)
(10,491)
—
(5,287)
—
(10,491)
(68,318)
(5,287)
(71,999)
(66,809)
(70,773)
(1,509)
(1,226)
(10,491)
(5,287)
(78,809)
(77,286)
(29,650)
(44,855)
(601)
(143)
(1,097)
1,739
(31,348)
(43,259)
A sensitivity of 10% has been selected as this is considered reasonable given the current level of both short term and long term interest
rates. A 10% movement in interest rates at the reporting date would have increased/(decreased) equity and profit and loss by the amounts
shown below based on the average balance of interest-bearing financial instruments held. This analysis assumes that all other variables
remain constant.
The analysis is performed only on those financial assets and liabilities with floating interest rates and is prepared on the same basis as for
2020.
Profit or Loss
Equity
10% Increase
10% Decrease
10% Increase
10% Decrease
2021 ($’000)
Cash and cash equivalents
Interest bearing liabilities
2020 ($’000)
Cash and cash equivalents
Interest bearing liabilities
13
(369)
7
(397)
(13)
369
(7)
397
—
—
—
—
—
—
—
—
These movements would not have any impact on equity other than retained earnings.
(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.
94
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
33. FINANCIAL RISK MANAGEMENT (CONTINUED)
(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 2022 (2020: 30 September 2021). Repayments comprise fixed quarterly
principal repayments of $1,000,000 along with accrued interest to September 2021 and $2,000,000 per quarter thereafter. In addition, the
Group has committed to a lump sum repayment of $29,000,000 from the proceeds of the sell down of its producing assets, which is
expected to complete on 1 October 2021. Therefore, as at 30 June 2021, there is not an unconditional right to defer settlement of this
amount for at least 12 months and $29,000,000 has been classified as “current” in the Balance Sheet. If the transaction does not complete,
this amount of $29,000,000 would revert to being payable on 30 September 2022. 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.
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
2021
$’000
1,609
(416)
(3)
(3)
2020
$’000
677
(153)
—
—
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
2021
$’000
(108)
132
2020
$’000
(62)
75
These movements would not have any impact on equity other than retained earnings.
(g) Fair Values
The carrying amounts of cash, cash equivalents, financial assets and financial liabilities, approximate their fair values.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
95
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
34. INTERESTS IN JOINT ARRANGEMENTS
Details of joint arrangements in which the Consolidated Entity has an interest and the name of the party with joint control are as follows:
Principal Activities
Oil & gas production
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration – application
Oil & gas exploration – application
Oil & gas exploration
2021
%
50.00
60.00
60.00
30.00
30.00
100.00
50.00
50.00
50.00
2020
%
50.00
60.00
60.00
30.00
30.00
100.00
50.00
50.00
50.00
OL4, OL5 and PL2 Mereenie (Macquarie1)
EP 82 (Santos2)
EP 105 (Santos2)
EP 112 (Santos2)
EP 125 (Santos2)
EP 115 North Mereenie Block (Santos2)
EPA 111 (Santos2)
EPA 124 (Santos2)
ATP 2031 Range Gas Project (IPL3)
1 Macquarie = Macquarie Mereenie Pty Ltd.
2 Santos = Santos Group companies.
3
IPL = Incitec Pivot Limited.
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.
Santos’ right to earn and retain participating interests in each permit is subject to satisfying various obligations in their respective farmout
agreement. The participating interests as stated assume such obligations have been met, or otherwise may be subject to change or
negotiation.
96
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
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
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
35,248
12
(30,172)
5,088
2020
$’000
666
4,243
1,409
—
6,318
52,074
225
301
52,600
3,494
46
731
712
119
—
5,102
439
187
3,461
21,433
25,520
28,296
38,541
10
(26,849)
11,702
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
97
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2021
35. EVENTS OCCURRING AFTER THE REPORTING PERIOD
Increased interest in EP112
Effective 31 July 2021, Central’s interest in EP112 increased from 30% to 45% as a result of joint venturer, Santos, not electing that Central
be carried for the first $3,000,000 of future Dukas well costs.
Asset Sale
On 17 September 2021 the agreement for the sale of 50% of the Group’s producing assets to New Zealand Oil & Gas Limited and Cue
Energy Resources Limited became unconditional and the transaction is expected to complete on 1 October 2021.
No other matter or circumstance has arisen between 30 June 2021 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.
98
CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
DIRECTORS’ DECLARATION
1.
In the Directors’ opinion:
a) the financial statements and notes set out on pages 52 to 98 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 2021 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 2021.
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
21 September 2021
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 99
INDEPENDENT AUDITOR’S REPORT
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 2021 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 2021
the consolidated statement of changes in equity for the year then ended
the consolidated statement of cash flows for the year then ended
the consolidated statement of comprehensive income for the year then ended
the notes to the consolidated financial statements, which include a summary of significant
accounting policies
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, www.pwc.com.au
Liability limited by a scheme approved under Professional Standards Legislation.
100 CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
Our audit approach
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
Key audit matters
● Amongst other relevant
topics, we
communicated the
following key audit
matter to the Audit and
Risk Committee:
- Sell-down of
Amadeus Basin
Production Assets
● Our audit focused on where
the Group made 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.
● For the purpose of our audit, we used
overall Group materiality of $1.74
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’s 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.
Key audit matters
Key audit matters are those matters that, in our professional judgement, were of most significance in our
audit of the financial report 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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
101
INDEPENDENT AUDITOR’S REPORT
Key audit matter
How our audit addressed the key audit
matter
Sell-down of Amadeus Basin Production
Assets (Refer to notes 10, 11 and 16)
During the year, the Group entered into a binding
agreement with New Zealand Oil and Gas Limited
(“NZOG”) and Cue Energy Resources Limited (“Cue”)
to sell 50% of its interest in the Amadeus Basin
Production Assets.
The transaction is subject to various regulatory and
other approvals.
The sell-down transaction was a key audit matter
because:
● of the significance of the assets ($57.97 million)
and related liabilities ($39.44 million) classified
as held for sale due to this transaction.
● the transaction price has been used by the Group
to determine fair value and therefore, assess the
recoverable amount of:
o
o
assets and liabilities held for sale
goodwill and the producing assets
cash-generating unit (CGU).
To evaluate the Group’s assessment of the assets and
liabilities classified as held for sale, we performed a
number of procedures including the following:
● Obtained and read the signed binding agreement
with NZOG and Cue and inspected evidence of
progress against conditions precedent for
completion.
● Reconciled the assets and liabilities classified and
disclosed as held for sale to the key terms and
clauses of the signed binding agreement.
● Assessed whether the assets and liabilities held
for sale met the definition of a discontinuing
operation under Australian Accounting Standard
AASB 5 Non-current assets held for sale and
discontinued operations.
To evaluate the Group’s assessment of recoverable
amount of the assets and liabilities held for sale,
goodwill and the producing assets CGU, we
performed a number of procedures including the
following:
● Compared the fair value less costs to sell by the
Group (based on the signed binding agreement)
to the carrying value and the resulting
recoverable amount of the total assets classified
as held for sale less total liabilities directly
associated with such assets.
● Assessed whether the composition of the
producing assets CGU was consistent with our
knowledge of the Group’s operations.
● Assessed whether the CGU appropriately
included all directly attributable assets and
liabilities.
● Assessed if the transaction price as per the
signed binding agreement meets the definition
of fair value less costs of disposal (FVLCD) in
Australian Accounting Standard AASB 136
Impairment of Assets and Australian
Accounting Standard AASB 13 Fair Value
Measurement.
● Tested the inputs and the mathematical
accuracy of the calculation to determine the
recoverable amount of goodwill and producing
assets CGU.
● Evaluated the adequacy of disclosures made in
note 16 of the financial statements, including
those regarding selection of method to compute
fair value less costs of disposal in light of the
requirements of the Australian Accounting
Standards.
102 CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
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 2021, 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.
Responsibilities of the directors for the financial report
The directors of the Company are responsible for the preparation of the financial report that gives a true
and fair view in accordance with Australian Accounting Standards and the Corporations Act 2001 and for
such internal control as the directors determine is necessary to enable the preparation of the financial
report that gives a true and fair view and is free from material misstatement, whether due to fraud or
error.
In preparing the financial report, the directors are responsible for assessing the 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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
103
INDEPENDENT AUDITOR’S REPORT
Report on the remuneration report
Our opinion on the remuneration report
We have audited the remuneration report included in pages 35 to 49 of the directors’ report for the year
ended 30 June 2021.
In our opinion, the remuneration report of Central Petroleum Limited for the year ended 30 June 2021
complies with section 300A of the Corporations Act 2001.
Responsibilities
The directors of the Company are responsible for the preparation and presentation of the remuneration
report in accordance with section 300A of the Corporations Act 2001. Our responsibility is to express an
opinion on the remuneration report, based on our audit conducted in accordance with Australian
Auditing Standards.
PricewaterhouseCoopers
Marcus Goddard
Partner
Brisbane
21 September 2021
104 CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
ASX ADDITIONAL INFORMATION
DETAILS OF QUOTED SECURITIES AS AT 15 SEPTEMBER 2021
Top holders
The 20 largest registered holders of the quoted securities as at 15 September 2021 were:
Name
Norfolk Enchants Pty Ltd
UBS Nominees Pty Ltd
Fanchel Pty Ltd
No. of
Shares
37,500,000
29,914,670
17,700,000
Mr Christopher Ian Wallin + Ms Fiona Kay McLoughlin + Mrs Sylvia Fay Bhatia
17,571,648
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Brazil Farming Pty Ltd
Citicorp Nominees Pty Limited
Macquarie Bank Limited
Chembank Pty Limited
Mr Raymond Driscoll + Mrs Karyn Driscoll + Mr Jarrod Driscoll
Mr Philip Gasteen
Kensington Capital Partners Pty Ltd
JH Nominees Australia Pty Ltd
Justwright Investments Pty Ltd
Mr Stuart Francis Howes
Mr Donald Leonard Cottee
Mr William Bambling + Mrs Joyce Bambling
Mr James Donald Bruce Cochrane + Mrs Joan Elizabeth Cochrane
18-19 Chembank Pty Limited
18-19 Garmi Holdings Pty Ltd
20
Garmi Holdings Pty Ltd
%
5.18
4.13
2.44
2.43
2.26
2.15
1.96
1.38
1.23
1.19
1.10
1.04
0.97
0.84
0.81
0.72
0.69
0.69
0.69
0.55
16,385,209
15,568,444
14,166,667
10,000,000
8,936,608
8,583,800
8,000,000
7,500,000
7,000,000
6,076,001
5,830,594
5,205,000
5,000,001
5,000,000
5,000,000
4,000,000
DISTRIBUTION SCHEDULE
A distribution schedule of the number of holders in each class of equity securities as at 15 September 2021 was:
Total 234,938,642 32.45
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
741
1,802
1,025
2,552
955
7,075
1
8
12
42
29
92
—
—
—
—
5
5
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
105
ASX ADDITIONAL INFORMATION
SUBSTANTIAL SHAREHOLDERS
Substantial shareholders as disclosed by notices received by the Company as at 15 September 2021 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 4,762 shares as at 15 September 2021):
Holders
2,370
Units
4,456,385
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 2021 Corporate Governance Statement reflects the corporate governance practices in place throughout the 2021 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/.
106 CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
INTERESTS IN PETROLEUM PERMITS AND PIPELINE
LICENCES
AT THE DATE OF THIS REPORT
PERMITS AND LICENCES GRANTED
Tenement
Location
CTP Consolidated Entity
Other JV Participants
Operator
Registered
Interest (%)
Beneficial
Interest (%)
Participant
Name
Beneficial
Interest (%)
EP82 (excl. EP82 Sub-Blocks)
Amadeus Basin NT
EP82 Sub-Blocks
Amadeus Basin NT
Santos
Central
EP105
EP112 1
EP115 (excl. EP115 North
Mereenie Block)
Amadeus/Pedirka Basin NT
Santos
Amadeus Basin NT
Amadeus Basin NT
EP115 North Mereenie Block2 Amadeus Basin NT
EP125
OL3 (Palm Valley)3
OL4 (Mereenie) 3
OL5 (Mereenie) 3
L6 (Surprise)
L7 (Dingo) 3
RL3 (Ooraminna)
RL4 (Ooraminna)
ATP909
ATP911
ATP912
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
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
60
100
60
30
100
60
30
100
50
50
100
100
100
100
100
100
100
50
60
100
60
45
100
100
30
100
50
50
100
100
100
100
100
100
100
50
Santos QNT Pty Ltd (Santos)
Santos
Santos
Santos
Macquarie Mereenie Pty Ltd
(Macquarie Mereenie)
Macquarie Mereenie
40
40
55
70
50
50
Incitec Pivot Queensland Gas Pty Ltd
50
Santos
Central
Santos
Santos
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
PERMITS AND LICENCES UNDER APPLICATION
Tenement
Location
CTP Consolidated Entity
Other JV Participants
Operator
Registered
Interest (%)
Beneficial
Interest (%)
Participant
Name
Beneficial
Interest (%)
EPA92
EPA111
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
Santos
Santos
50
50
PIPELINE LICENCES
Pipeline Licence
Location
CTP Consolidated Entity
Other JV Participants
Operator
Registered
Interest (%)
Beneficial
Interest (%)
Participant
Name
Beneficial
Interest (%)
PL2 3
PL30 3
Amadeus Basin NT
Amadeus Basin NT
Central
Central
50
100
50
100
Macquarie Mereenie
50
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
107
INTERESTS IN PETROLEUM PERMITS AND PIPELINE
LICENCES
AT THE DATE OF THIS REPORT
Notes:
1 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 as a result, Santos’ interest will
decrease from 70% to 55% (Central’s interest will increase from 30% to 45%).
2 On 12 December 2019 Central received notice from Santos of its intention to withdraw from EP115 North Mereenie Block effective 31 January 2020.
3 On 25 May 2021 Central announced an agreement to sell 50% of its existing interests in Mereenie, Palm Valley and Dingo to subsidiaries of New Zealand Oil & Gas
Ltd and Cue Energy Resources Ltd. The transaction is expected to settle on 1 October 2021.
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 The 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.
108 CENTRAL PETROLEUM LIMITED 2021 ANNUAL REPORT
CORPORATE DIRECTORY
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS
Mr Michael (Mick) McCormack BSurv, GradDipEng, MBA, FAICD, Non-Executive Director, Chair
Mr Leon Devaney BSc MBA, Managing Director and Chief Executive Officer
Mr Stuart Baker BE(Elec), MBA, AICD, Non-Executive Director
Mr Stephen Gardiner BEc (Hons), Fellow - CPA Australia
Ms Katherine Hirschfeld AM, BE(Chem), HonFIEAust, FTSE, FIChemE, FAICD, Non-Executive Director
Dr Agu Kantsler BSc (Hons), PhD, GAICD, FTSE, Non-Executive Director
GROUP GENERAL COUNSEL AND COMPANY SECRETARY
Mr Daniel White LLB, BCom, LLM
REGISTERED OFFICE
Level 7, 369 Ann Street, Brisbane, Queensland 4000
+61 7 3181 3800
Telephone:
Facsimile:
+61 7 3181 3855
www.centralpetroleum.com.au
AUDITORS
PricewaterhouseCoopers
480 Queen Street, Brisbane, Queensland 4000
BANKERS
ANZ Banking Group
111 Eagle 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.
2021 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 109
Head Office
Level 7, 369 Ann Street, Brisbane, Qld 4000
Postal Address
GPO Box 292, Brisbane, Qld 4001
Email: info@centralpetroleum.com.au
www.centralpetroleum.com.au