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2023 ReportPeers and competitors of Central Petroleum:
Lonestar Resources LtdANNUAL
REPORT
C E N T R A L P E T R O L E U M L I M I T E D
A C N 0 8 3 2 5 4 3 0 8
2023
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.
The failure of one of our joint-venturers to perform will delay
the three sub-salt exploration wells that were planned to
explore for helium, naturally-occurring hydrogen and natural
gas. We are working to restructure and refinance the program
so that these exciting prospects can be tested.
On the ground, we continue to work with the people and
businesses in our local communities and the Traditional Owners
of the land on which we operate. We appreciate their
contributions to our success and hope that the opportunities
and support we provide in these regions have long-lasting
impact.
I thank my Board colleagues, Leon, our CEO and all of our staff at
Central who have worked throughout the year to provide our
customers with reliable and affordable energy.
Our strategic review continues to explore various opportunities
to realise value for shareholders. I am sure you are aware of the
issues which have confronted the industry since we started the
review late last year. The gas price cap, a proposed mandatory
code of conduct (which is now law) and the safeguard
mechanism, have all been matters which caused material
uncertainty in the sector. As was well reported in the media
these material changes impacted the strategic decisions and
plans at the international and national levels. These matters are
now behind us, but nonetheless, have slowed our progress. We
hope to be able to conclude this process in the near future and
appreciate the patience of our shareholders and staff.
We remain confident in the future of our asset portfolio. The
enduring value of our producing assets has been demonstrated
with drilling success and reserve upgrades, helium is emerging
as an additional income stream and our portfolio of exploration
prospects continues to attract attention from potential
investors.
We look forward to the year ahead and to sharing our progress
with our shareholders.
Thank you,
Mick McCormack, Chair
19 September 2023
Dear Shareholders,
It has been a popular topic in recent years to demonise natural
gas as the harbinger for all manner of ills, from irreversible
planet-destroying climate change to rapidly-rising energy costs.
Against this backdrop, the Federal Government’s intervention in
gas markets during the year appeared ill-conceived, but once
the dust had settled, it seems unlikely to directly affect Central’s
gas marketing and commercial prospects.
It is from within this confusing environment of fact and fantasy
that voices of reason are now being respected, confirming the
critical role that natural gas will play in the transition to a
cleaner energy future.
It is becoming increasingly clear that it is not only the southern
states that will face significant gas supply challenges in coming
years. Northern Australia, the home of remote mining
operations providing rare minerals, critical for the renewables
transition, is facing reducing gas supplies as traditional offshore
sources decline.
With over 55 PJs of uncontracted 2P reserves, Central’s gas
fields are playing an increasingly important role in producing
vital gas supplies for customers across the region.
This supply/demand dynamic has provided a strong gas market
for Central, with robust demand and strong term gas prices
vindicating our investments in additional production from our
established fields.
Investment to increase production at Mereenie and Palm Valley
this year has added over 11 TJ/day of gas into the market (100%
JV) at a time when offshore production in the NT experienced
significant production decline and alternate suppliers were
struggling to meet demand.
Realised gas prices were significantly higher than the previous
year and forward term gas contracts reflect continued gas
supply constraints in the NT and Mt Isa regions.
Combined with our recent reserve upgrades, a strong term gas
market should continue to support our operational cash flows
and financial strength going forward.
In addition to the proven natural gas resources of the Amadeus
Basin, there are strong indications that the basin could provide
Australia with supplies of other gases – most notably helium,
which already exists in low concentrations in our existing gas
streams, and has previously been detected in commercial
concentrations in previous exploration wells.
We are now advancing plans for a helium recovery unit at
Mereenie to produce helium for the Australian market. The
proposed Mereenie project would then be the sole source of
domestically-produced helium, helping to satisfy Australia’s
strategic need for helium which is used in many critical health
and technology applications.
Production of helium at Mereenie would add a valuable new
income stream for Central, and given the world-wide paucity of
helium sources, elevate the attractiveness of Amadeus Basin’s
sub-salt formations.
Dear Fellow Shareholders,
I’m pleased to present Central Petroleum’s FY2023 Annual
Report.
It has been an eventful year for the Company, having maximised
production during a winter energy crisis, re-prioritised an
exploration drilling program, witnessed new government market
intervention, seen our sub-salt exploration program delayed by a
defaulting joint venture partner, booked reserve upgrades and
embarked on the path towards commercial helium production.
The winter of 2022 will be remembered for the energy ‘crisis’
prompted by off-line coal fired generation and colder weather
which resulted in historically high pricing for electricity, gas and
oil. Central responded by supplying 77 TJ of gas to eastern
markets over the winter months to help alleviate critical
shortages and re-prioritised capital from its exploration program
to near-term production opportunities.
This resulted in the Palm Valley 12 well, unsuccessful in its
exploration and appraisal targets, ultimately flowing gas at over
11 TJ/day (100% JV), more than doubling capacity at the Palm
Valley field whilst providing welcome new supply to customers in
the Northern Territory and in eastern states. The performance of
this well allowed Central to book 3 PJ of new gas reserves and
supports the drilling of future wells at Palm Valley to target
additional gas production and reserve additions.
We also brought on additional production capacity at Mereenie
towards the end of the year, and would have recorded higher
sales volumes if not for a number of temporary outages on the
Northern Gas Pipeline during the year. Market demand for gas
remains strong and higher gas prices offset the impact of the
lower volumes and higher costs, resulting in our per unit gross
profit increasing 12% from FY2022.
These increased margins are a clear indication of the strong
performance and value of the production assets, with $39.3
million of revenue recognised, generating underlying EBITDAX of
$15.8 million. Cash balances were $13.8 million, and debt
reduced to $28.1 million at 30 June. A further $11 million is
potentially available under the extended loan facility, providing
additional financial flexibility for future development activity.
Having secured sufficient capital to proceed with the three well
sub-salt exploration program, it was disappointing that our new
joint venture partner has been unable to meet its funding
commitments. This much-anticipated program, targeting
substantial helium, hydrogen and natural gas resources, will now
be delayed while we work to restructure the joint venture and
associated exploration program.
We have seen increasing interest in our sub-salt exploration
permits off the back of a proposed helium production facility at
Mereenie. In August 2023 we announced a Memorandum of
Understanding to work with experienced US-based helium
developer and producer, Twin Bridges, towards a final
investment decision for the construction of a Helium Recovery
Unit (HRU) at Mereenie. The arrangement would see Twin
Bridges design, build, fund and own the plant, providing Central
with a share of future profits with minimal capital outlay and
financial risk. Given strong helium market dynamics and
brownfield economics associated with building and operating a
HRU at Mereenie, the project appears very attractive.
Successful separation of helium from the existing gas stream on a
commercial scale at Mereenie would demonstrate the potential
of the Amadeus Basin as a world-class helium resource, and in
particular, the large sub-salt prospects where relatively-high
helium content has previously been measured.
Advancing the valuable helium potential of our Amadeus Basin
interests will be a priority for Central in the next year, but will not
detract from our focus on bringing more gas supply to Australian
customers. New development wells are planned at Mereenie and
are progressing through the joint venture approvals process. We
are also pushing to advance exploration activity at the
Mamlambo oil prospect and the Zevon sub-salt prospect through
new farmout arrangements.
Whilst the Board continues to consider its options under a
strategic review, Central remains focussed on creating
opportunities and progressing value accretive projects that
ensure shareholders receive the most value possible from their
assets. I thank our staff for their dedication in safely and
responsibly operating our remote gas fields during the year and
in advancing our growth-orientated projects.
I expect the next year to be a period of key milestones and
decisions for the Company, and remain confident that the value
of our existing production and brownfield development
opportunities will become increasingly visible as market price
regulation and escalating costs create further barriers to new gas
exploration and development.
I can assure our shareholders that everyone at Central is focussed
on maximising shareholder return from our portfolio of assets,
and we look forward to sharing that progress as the year unfolds.
Leon Devaney, CEO
19 September 2023
• The Group added an additional 5.9 PJ of Proved and Probable (2P) gas reserves at 30 June 2023, representing an increase of 8%
(before production) to 75 PJe reflecting drilling and production results at Palm Valley and updated Dingo reservoir modelling.
• The Palm Valley 12 well was successfully tied into the Palm Valley processing facilities and flowed gas to market from late
November 2022 at greater than 10 TJ per day.
• New gas sales agreements for the sale of gas were secured with:
-
-
Shell Energy for supply of 0.91 PJ of gas in CY2025; and
South 32 for supply of 0.55 PJ of gas over two years from 1 January 2023.
• Average sales prices were up 17% on FY2022 at $7.90 / GJe.
• Annual revenue from hydrocarbon sales of $38.2 million was up 12% from FY2022 on a like for like basis.
•
In August 2023, agreement was reached to progress towards a final investment decision for construction of a helium recovery
unit at Mereenie, demonstrating the potential of the Amadeus Basin as a world-class helium resource.
Underlying EBITDAX: Decreased 6% to $15.7m in FY2023*
(Earnings before interest, tax, depreciation, impairment,
exploration costs, and profit on asset disposals)
Operating revenue: Decreased 7% to $39.3m in FY2023*
2P Reserves increased to 75.0 PJe after current year production. Refer
Reserves and Resources Statement on page 20.
Net Debt: $14.3 million at 30 June 2023
* Note that Central disposed of 50% of its interests in its producing fields as at 1 October 2021, an effective 12.5% reduction in annual production capacity for FY2023
in comparison with FY2022
The Consolidated Entity had a loss after income tax for the year ended 30 June 2023 of $8.0 million (2022: profit of $21.3 million).
The above result was after expensing exploration costs of $13.1 million (2022: $21.6 million). The Group’s policy is to expense all
exploration costs as incurred.
To assist with comparability of this year’s result, EBITDAX, EBITDA and EBIT have been reported against the underlying results in FY2022.
Note that a direct comparison of annual results will be impacted by :
1. The FY2022 profit on sale of the Group’s interests in its producing properties which completed on 1 October 2021 (which is
excluded from underlying results to assist with comparability); and
2. The decrease in revenues, production costs, capital expenditure and exploration costs resulting from the 50% reduction in the
Group’s equity interest in its producing assets during FY2022 (from 1 October 2021).
The table below shows key metrics for the Group (refer Note 1(a) regarding restatement of expenses by function for FY2022):
Decrease in FY23 production capacity due to asset sale
Net Sales Volumes
-
-
Natural Gas (TJ)
Oil & Condensate (bbls)
Sales Revenue ($‘000)
Gross Profit7 ($‘000)
Underlying EBITDAX1 ($‘000)
Underlying EBITDA2 ($’000)
Underlying EBIT3 ($‘000)
Underlying loss after tax4 ($’000)
Statutory (loss)/profit after tax ($‘000)
Net cash (outflow)/inflow from Operations5 ($’000)
Capital expenditure6 ($‘000)
4,664
30,293
39,255
12,847
15,749
2,656
(4,210)
(8,170)
(7,960)
(2,056)
12,815
5,993
47,197
42,151
14,800
16,746
(4,901)
(11,680)
(15,239)
21,320
3,640
10,053
(1,329)
(16,904)
(2,896)
(1,953)
(997)
7,557
7,470
7,069
(29,280)
(5,696)
2,762
(12.5)%
(22.0)%
(36.0)%
(7.0)%
(13.0)%
(6.0)%
154.0%
64.0%
46.0%
(137.0%)
(156.0)%
27.0%
1 Underlying EBITDAX is Earnings before Interest, Tax, Depreciation, Amortisation, Impairment and Exploration costs and profit on disposal of interests in producing
properties (refer reconciliation below).
2 Underlying EBITDA is Earnings before Interest, Tax, Depreciation, Amortisation, Impairment and profit on disposal of interests in producing properties.
3 Underlying EBIT is Earnings before Interest, Tax and profit on disposal of interests in producing properties.
4 Underlying profit / loss after tax is statutory profit after tax, before profit on disposal of interests in producing properties.
5 Cashflow from Operations includes cash outflows associated with exploration activities.
6 Capital expenditure on tangible assets.
7 Refer Note 1(a) regarding restatement of FY2022 expenses by function.
Underlying EBITDAX, underlying EBITDA and underlying EBIT are non-IFRS measures that are presented to provide an understanding of the
underlying performance of the Group. The non-IFRS information is not subject to audit review, however the numbers have been extracted
from the financial statements which have been subject to review by the Group’s auditor. A reconciliation to profit before tax is provided
below.
EBITDAX
Underlying EBITDAX for the year was $15.7 million, down 6% from $16.7 million in 2022 and consistent with the reduced earnings base which
resulted from the disposal of 50% of the Group’s interests in the Amadeus Basin producing properties on 1 October 2021 and reduced sales
volumes. Further discussion on revenues and gross profit are included below.
Underlying EBITDAX are earnings before interest, tax depreciation, amortisation, impairment, exploration and profit on disposal of interests
in producing properties. Underlying EBITDAX is used by management as an indicative measure of underlying operating profit from operations
as it excludes non-cash items, the costs of finance and expensed exploration costs and is reconciled to statutory profit below.
It should be noted however that Underlying EBITDAX is only an indicative measure of underlying cash profit from operations. There are other
significant non-cash items included in underlying EBITDAX, such as share based payments amounting to $0.8 million this year (2022:
$1.5 million). Revenues recognised may also not reflect actual cash receipts, as some gas revenues relate to presold gas for which cash was
received in previous periods and amounts received under ‘take or pay’ gas contracts are not recognised as revenue until the gas is taken or
forfeited by the customer.
Statutory (loss)/profit before tax
Impact of farmout to Peak Helium net of impairment costs
Profit on disposal of 50% interest in Amadeus Basin producing properties
Underlying loss before tax
Net finance costs and restatement of financial assets
Underlying EBIT
Depreciation, amortisation and impairment
Underlying EBITDA
Exploration expenses
Underlying EBITDAX
(7,960)
(210)
—
(8,170)
3,960
(4,210)
6,866
2,656
13,093
15,749
21,320
—
(36,559)
(15,239)
3,559
(11,680)
6,779
(4,901)
21,647
16,746
Sales Volumes
Sales volumes were 23% lower than FY2022 at 4.8 PJe, with most of this difference due to the reduction in the Group’s equity interests in
the Amadeus Basin producing properties from 1 October 2021. On a like-for-like basis, volumes were 3% lower than FY2022 due to outages
on the Northern Gas Pipeline affecting East Coast deliveries and natural field decline, offset by increased production from the new Palm
Valley well, commissioned in late November 2022.
Note: Oil converted at 5.816 GJ/bbl.
Sales Revenue
Central recorded sales revenue of $39.3 million, down 7% on FY2022, reflecting the lower volumes, lower global oil prices and partially
offset by higher realised gas prices. Average realised prices were up 17% on FY2022 at $7.90/GJe, reflecting increased domestic gas sales
into the higher-priced east coast spot market. Sales revenue included $1.0 million released from deferred take-or-pay balances.
Gross Profit
Gross profit was $12.8 million, inclusive of non-cash depreciation and amortisation costs, a decrease of 13% on FY2022, in line with
reduced equity interests following completion of the partial sale of interests in the producing assets from 1 October 2021. On a per unit
basis this represents a gross profit of $2.65/GJe which is an increase of 12% from $2.36/GJe for FY2022, as the higher average sales price
(up $1.17/GJe) more than offset the higher per-unit cost of sales. The unit cost of sales increased by 25%, reflecting fixed costs spread over
lower volumes and includes additional transportation costs for spot sales to the East Coast market.
Net Assets/Liabilities
At 30 June 2023, the Group had a net asset position of $19.4 million compared to $26.5 million at 30 June 2022, reflecting the current year
loss 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 $15.2 million. These liabilities will be transferred to revenue as gas is supplied to the customer or
forfeited to Central under take-or-pay contracts and therefore do not represent a cash liability to the Group. During the year, 0.71 PJ of
previously over-lifted gas was repaid to a joint venture partner and 0.9 PJ of pre-sold gas was delivered.
Debt
The Group repaid $4.6 million of loan principal during the year and drew down $1 million under a new facility. The outstanding balance of
the loan facility at 30 June 2023 was $28.1 million with $4.7 million due for repayment in FY2024.
Net debt increased $4.1 million to $14.3 million at 30 June 2023, reflecting reduced cash balances resulting largely from exploration
activities.
The consolidated debt ratio at 30 June 2023 increased slightly to 0.29 (2022: 0.26). Debt ratio is defined as: Total Debt/Total Assets. Net
gearing at 30 June 2023 was 27% (2022: 11% or 21% if re-based to 30 June 2023 market capitalisation). Net gearing is calculated as: Net
Debt / (Market capitalisation + Net Debt). Debt service is supported by long term gas sales contracts and the Group’s certified oil and gas
reserves.
Net Cash Flow
Cash balances decreased by $7.8 million over the year. Net cash flow from production operations for 2023 was $13.8 million compared to
$19.8 million for 2022, with the decrease reflecting the reduced interests in the Amadeus Basin producing properties from 1 October 2021
and lower sales volumes.
After net interest payments of $2.3 million, $4.1 million of corporate and staff expenses and $9.6 million for exploration activities, net cash
outflow from operating activities was $2.1 million.
During the year, Central invested $2.9 million in capital projects, including ongoing work on installation of a compressor to recover flare gas
at Mereenie and other sustaining capital expenditure at the three producing fields. A further $10.5 million of Central’s share of Palm Valley
and Dingo exploration costs and $9.9 million of development costs were paid (“carried”) by joint venturers under the terms of the partial
asset sale. Central repaid $4.6 million of debt during the year after drawing down an additional $1 million from the expanded facility.
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.
59.36
15.80
(14.53)
22.19
22.19
.—
123.48
17.81
(81.73)
(5.62)
(1.53)
65.05
5.28
5.41
33.40
25.01
.—
107.85
25.92
(70.77)
1.58
6.75
59.83
7.74
0.25
26.09
26.09
.—
108.28
37.17
(66.81)
3.69
8.25
42.15
21.65
21.32
53.31
16.75
—
53.85
21.65
(30.81)
26.53
22.31
39.26
13.09
(7.96)
15.96
15.75
—
60.19
13.83
(27.53)
19.39
7.11
Operating Data
Gas Sales (TJ)
Oil Sales (barrels)
No. of employees at 30 June
10,229
97,392
99
11,822
89,016
92
9,820
77,255
85
5,993
47,197
88
4,664
30,293
80
Central Petroleum Limited is an ASX-listed oil and gas producer, with a portfolio of producing and prospective tenements across the
Northern Territory (NT) and Queensland. Central is the operator of the largest onshore gas producing fields in the NT, supplying industrial
customers, electricity generators and senior gas distributors from three producing fields near Alice Springs.
Location of Central’s producing oil and gas fields
Gas
Crude and Condensate
Total
PJ
bbls
PJe
4.7
30,293
4.8
6.0
47,197
6.3
Note: Oil is converted to Petajoule equivalent (PJe) at 5.816 GJe/bbl.
Central’s sales volumes were 23% lower than FY2022 (note that
Central had higher ownership interests in the producing fields for the
first quarter of FY2022). On a like-for-like ownership basis, volumes
were 3% lower than FY2022, with new production from Palm Valley
offsetting the impact of temporary pipeline outages, natural field
decline and lower demand for gas from the Dingo field.
Northern Territory
Ownership interests
Central Petroleum (operator)
Macquarie Mereenie Pty Ltd
NZOG Mereenie Pty Ltd
Cue Mereenie Pty Ltd
25.0%
50.0%
17.5%
7.5%
Gas
Oil
Total2
PJ
mmbbl
28.7
0.34
37.5
0.38
45.6
0.05
PJe
30.7
39.7
45.9
Well recompletions boosted production capacity
(May 2023)
1 Reserves and resources are as at 30 June 2023. 2C gas resources include 27 PJ
Agreement to progress planning for construction of
attributable to the Stairway Sandstone.
2 Oil converted at 5.816 PJ/mmbbl
a helium recovery unit (August 2023).
Full field gas production for the year was 9.5 PJ, averaging 26.2 TJ/d, down from the 11.6 PJ (31.7 TJ/d) produced in FY2022, impacted by
several temporary shutdowns to the Northern Gas Pipeline during the year. Consequently, oil production was also lower at 348 bbl/d.
Central’s share of this Mereenie gas and oil production for FY2023 was 2.6 PJe, with a reduced ownership interest of 25% applying from 1
October 2021 when the partial asset sale completed (previously 50%).
A recompletion program was undertaken in the fourth quarter, with five existing wells which had previously produced from deeper zones
being perforated to access gas in the shallower Pacoota 1 interval. The program increased field capacity by 1.4 TJ/d (0.35 TJ/d net to
Central).
Two new development wells are planned at Mereenie in the next 12 months to further increase production and offset natural field decline.
Critical long lead items have been ordered and rig selection is progressing prior to final joint venture approval.
Central and its Mereenie joint venturers are working with Twin Bridges LLC (Twin Bridges), a private US company specialising in
helium appraisal and production, to progress a helium recovery unit (HRU) at Mereenie towards a final investment decision (FID).
It is proposed that the HRU will be sized to process up to 30 TJ/d of Mereenie gas, which typically contains circa 0.2% helium,
extracting up to 60,000 scfd of helium using proven membrane technology.
Preliminary technical and market reviews have been completed, with solid project economics leveraging on strong helium markets
and the brownfield economics afforded by the existing gas stream and infrastructure at Mereenie.
Work is underway to achieve the necessary conceptual, design, engineering, commercial and financial milestones required to reach
FID for the construction of the HRU at Mereenie. If the project proceeds, Twin Bridges will design, build, fund and own the HRU
plant which will be integrated with the existing Mereenie gas processing facility operated by Central. Twin Bridges will market the
produced helium with offtake arrangements already well advanced. Profits would be shared 50/50 between Twin Bridges and the
Mereenie JV (Central 25% interest).
Northern Territory
Ownership interests
Central Petroleum (operator)
NZOG Palm Valley Pty Ltd
Cue Palm Valley Pty Ltd
50.0%
35.0%
15.0%
Gas
PJ
12.6
13.4
4.6
1 Reserves and resources are as at 30 June 2023.
PV12 well drilled and commissioned, more than
doubling field production capacity (November
2022).
1P gas reserves increased by 27% (July 2023).
Production from the Palm Valley field was boosted by the commissioning of the successful PV12 production well in late November. The
new well increased average field production from 5.2 TJ/d in October 2022 to a peak of 13.5 TJ/d in January 2023. The field averaged gas
sales of 9.2 TJ/d through FY2023, recording an aggregate of 3.3 PJ, up 43% from 2.4 PJ in FY2022.
Central’s share of Palm Valley gas sales for FY2023 was 1.7 PJ, with a reduced ownership interest of 50% applying from 1 October 2021
when the partial asset sale completed (previously 100%).
The successful P12 well, drilled laterally to a measured depth of 3,039m in the Pacoota-1 Sandstone, flowed gas at 11.8 mscfd when tested
in October 2022 and was brought online as a production well in late November. This followed an unsuccessful PV12 exploration sidetrack,
which was drilled into the deeper P2/P3 Sandstones after plans to drill to the deep Arumbera Sandstone were revised in July 2022 to
reduce drilling risks.
Success at PV12 not only boosted production, but has also resulted in a reserves upgrade, adding 3 PJ of Proved (1P) gas reserves to
Central’s gas reserves at Palm Valley.
The successful horizontal PV13 and PV12 wells, which were commissioned in May 2019 and November 2022 respectively, support the
drilling of additional wells targeting gas reserves and production. Planning for additional wells is progressing.
The deeper Arumbera Sandstone has potential as a significant gas resource and remains an exploration target at Palm Valley. The
Arumbera Sandstone is the production reservoir at the Dingo gas field, 100km to the east.
Northern Territory
Ownership interests
Central Petroleum (operator)
NZOG Dingo Pty Ltd
Cue Dingo Pty Ltd
50.0%
35.0%
15.0%
Gas
PJ
19.4
21.9
—
1 Reserves and resources are as at 30 June 2023.
1P gas reserves increased by 23% (July 2023).
The Dingo Gas Field supplies gas through a dedicated 50 km gas pipeline to Brewer Estate in Alice Springs for use in the Owen Springs
Power Station.
Sales volumes averaged 3.3 TJ/d across the year, an aggregate of 1.2 PJ, down 11% on FY2022 due to demand reverting to FY2020 and
FY2021 levels. The daily contract volume of 4.4 TJ/d is subject to take-or-pay provisions under which Central will be paid in January 2024 for
any gas nomination shortfall by the customer in CY2023.
Central’s share of gas sales for FY2023 was 0.6 PJ, with a reduced ownership interest of 50% applying from 1 October 2021 when the partial
asset sale completed (previously 100%).
Additional development wells can be drilled in the future at Dingo to maintain contracted gas volumes when warranted by natural field
decline and plans to add field compression are being investigated as a capital-effective interim alternative.
The deeper Pioneer Sandstone, which has flowed gas at the nearby Ooraminna prospect, and the Areyonga Formation lie below the existing
production reservoir and could hold significant gas resources. A deep exploration well, previously scheduled for 2022, has been deferred to
prioritise capital for production enhancement at Mereenie.
Surat Basin, Queensland
Central - 50% Interest, Incitec Pivot Queensland Gas Ltd (IPL) - 50%
Gas
PJ
— —
135
Central and joint venture partner, Incitec Pivot Limited are
progressing appraisal for the 77km2 Range coal seam gas
(CSG) project which is strategically located in the heart of
Queensland’s CSG province which hosts thousands of wells
producing from the same coal measures at similar depths.
Production testing of three pilot wells continued throughout
the year, with gas aggregate production rates increasing to
approximately 100,000 scfd at the end of June from 40,000
scfd a year ago. Central and Incitec Pivot are considering
plans to drill new pilot wells in the northeast of the permit.
Central Petroleum holds a significant portfolio of exploration opportunities across the Amadeus, Wiso, Georgina and Surat Basins in the
Northern Territory and Queensland. The total area held by Central for exploration is 173,122 km2 (64,153 km2 granted and 108,969 km2
under application).
Location of Central’s Petroleum Permits, Licences and Applications in Central Australia
Central Petroleum has significant operations within the proven Amadeus Basin, which has some of Australia’s largest prospective onshore
resources of conventional gas. The Amadeus Basin has provided reliable, high-quality oil and gas since the 1980s, yet it is relatively under-
explored and is believed to hold significant additional gas resources, including helium and naturally-occurring hydrogen, with good
prospectivity for oil on the western flank of the basin.
Over 100 potential oil and gas targets have been identified within Central’s Amadeus Basin footprint. Several high priority targets which
can be drilled conventionally and without stimulation (hydraulic fracturing) have been identified, including:
•
•
Large sub-salt targets with helium and hydrogen potential: The Amadeus Basin contains several large, potentially multi-Tcf sub-salt
targets that are also prospective for helium and hydrogen.
In-field opportunities: There are opportunities to target other intervals at Mereenie, Palm Valley and Dingo which are not currently
the principal production zones in each field. If successful, production wells could be tied into existing production facilities relatively
quickly and efficiently; and
• Other opportunities: Oil and gas opportunities are located close to existing producing fields from intervals which have been known to
produce oil or gas from nearby wells.
Amadeus Basin, Northern Territory
The Amadeus Basin hosts sub-salt targets within the Heavitree Formation and the fractured granitic basement sealed by extensive
evaporitic units of the upper Gillen Formation. In addition to hydrocarbons, the presence of radiogenic basement rocks and an evaporitic
sealing unit has created the ideal conditions for a helium and hydrogen play in the sub-salt section of the Amadeus Basin.
Helium is contained at low levels in gas flows from Central’s producing fields, Mereenie, Palm Valley and Dingo, and previous exploration
wells at Mt Kitty and Magee have shown high concentrations of helium and hydrogen. These high-value non-hydrocarbon gases are
generally associated with granitic basement and sub-salt prospects and Central is progressing a number of projects in the Amadeus Basin.
A major catalyst for a new phase of exploration is the planned construction of a helium recovery unit at the Mereenie gas field. Successful
production of helium at Mereenie would demonstrate the potential of the Amadeus Basin as a world-class helium resource, where Central
has a material position in several sub-salt prospects.
While helium concentrations of >0.3% are considered helium-rich, helium concentrations of 6% were recorded at the Magee-1 well and gas
flows at Mt Kitty contained 9% helium. Central is seeking to drill several sub-salt appraisal/exploration wells in the Southern Amadeus to
further test these prospects along with the promising Dukas lead. Seismic data will also be acquired at the Zevon lead to the north-west of
the Mereenie field later this year to identify the location for a possible exploration well.
Location of sub-salt targets
Progress on the Jacko Bore (Mt Kitty), Mahler (Magee) and Dukas explorations wells has been delayed while the joint ventures are
restructured and funded following the apparent financial failure of one of the key joint venturers.
Jacko Bore 2 (EP125)
Central 24%; Peak Helium 56%; Santos 20%
The proposed Jacko Bore 2 exploration well will target helium, naturally-occurring hydrogen and natural gas in the fractured basement by
re-entering the existing Mt Kitty-1 (Jacko Bore-1) well and drilling a deviated/horizontal sidetrack to test up to 500m of the fractured
basement reservoir at a depth of approximately 2,000m. The vertical Mt Kitty-1 exploration well flowed at up to 530,000 scfd, including
11.5% hydrogen and 9% helium.
Mahler (EP82)
Central 29%; Peak Helium 51%; Santos 20%
The proposed Mahler exploration well will target helium, naturally-occurring hydrogen and natural gas in the fractured basement and
Heavitree formation at depths up to 2,000m. The well is planned to be drilled up-dip and approximately 20km to the southeast of the Magee-
1 exploration well which flowed gas, including 6.2% helium.
Dukas 2 (EP112)
Central 35%; Peak Helium 35%; Santos 30%
The proposed Dukas-2 well is planned to follow the Dukas-1 exploration well which was drilled in 2019 and suspended after encountering
hydrocarbon-bearing gas from an overpressured zone close to the primary target at a depth of 3,704m. Traces of helium and hydrogen
were detected in mud gases associated with the overpressured zone. The Dukas-2 well will target the same tight sandstone in the
Heavitree formation below the salt seal with a higher-capacity rig.
Central estimates that its share of gas resources across the three prospects (prior to any JV restructure) are:
Helium
Hydrogen
Natural gas
4.3
5.3
9.4
39.9
50.8
259.7
0.6
0.6
2.9
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 a risk of discovery and a risk of development.
Further exploration appraisal and evaluation is required to determine the existence of a significant quantity of potentially recoverable
hydrocarbons/gases.
Additional resources guidance
The resources for the Dukas, Jacko Bore and Mahler prospects were first reported to ASX on 18 April 2023.
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.
Zevon (EP 115)
Central – 100% interest
The Zevon sub-salt lead in EP115 has been defined as a potentially very large closure (circa 1,600 km2) from seismic and gravity studies. It is
located in the north-western section of the Amadeus Basin between the Mereenie oil & gas field and the Surprise oil field.
Regional geological play mapping has highlighted that this area has the potential to be highly prospective for helium and hydrogen in
association with hydrocarbon gasses.
A short 2D seismic survey planned to further define the Zevon lead and identify locations for an exploration well.
Palm Valley (OL3); Dingo (L7); Mereenie (OL4/OL5), Amadeus Basin, Northern Territory
Central’s producing fields at Mereenie, Palm Valley and Dingo are comprised of several vertical layers of producing and potential oil and
gas reservoirs. There are opportunities to target other intervals which are not currently the principal production zones in each field. If
successful, production wells could be tied into existing production facilities relatively quickly and efficiently.
The deeper targets remain to be explored at a later date, as capital for the planned 2022 deep exploration wells was redirected to a
shallower target at Palm Valley and higher-priority production enhancement projects.
Palm Valley Deep (OL3)
Central - 50% interest (operator)
The Palm Valley Deep target has an estimated mean prospective resource of
123 PJ (61.5 PJ net to Central) in the deep Arumbera Sandstone (depth circa
3,500m) which is the productive interval at the Dingo field. A new gas
resource of this size at Palm Valley would be a catalyst for a significant
expansion of field production capacity and economic field life (current 2P gas
reserves are 13 PJ net to Central).
The PV12 exploration well, drilled in 2022 was to target the deep Arumbera
Sandstone, but after encountering difficult drilling conditions and reaching a
depth of 2,335m, the joint venturers decided in July 2022 to replace the
original PV Deep target with the lower P2/P3 target at a depth of
approximately 2,060m. The lateral well drilled into the P2/P3 Sandstones did
not detect gas flows and formation water was encountered.
A second lateral well was then drilled into the P1 Sandstones, the normal
producing zone at Palm Valley and flowed gas at 11.8 mscfd when tested in
October 2022 and was successfully brought online as a production well in late
November 2022.
Dingo Deep (L7)
Central - 50% interest (operator)
The Dingo Deep target has an estimated mean prospective resource of 69 PJ (34.5 PJ net to Central) in the deeper Pioneer Sandstone and
Areyonga Formation at a depth of up to 3,700m. Both formations have had gas shows with flows to surface achieved from the Pioneer
Sandstones at the Ooraminna well. A successful exploration test would open up a new play fairway in the basin and could prompt the
construction of new processing and pipeline infrastructure from the Dingo field which currently has 19 PJ of 2P gas reserves (net to
Central).
Mereenie Stairway (OL4/OL5)
Central - 25% interest (operator)
The Stairway Sandstones which overlie the deeper producing Pacoota Sandstones at Mereenie are estimated to contain 108 PJ of 2C
contingent gas resource (27 PJ net to Central). Gas has flowed from the Upper Stairway Sandstone while drilling deeper production wells,
providing a good indication of the presence of open natural fractures in the crestal region of the Mereenie field. If successful, production
from the Stairway would significantly increase production capacity and the economic life of the Mereenie field which currently has 2P gas
reserves of 39 PJ (net to Central).
Location map of immediate in-field and near-term exploration opportunities
Amadeus Basin, Northern Territory
Central has identified several other promising lower-risk, high reward exploration targets close to productive areas which can be pursued
relatively quickly once capital is allocated. The targets include:
Mamlambo (L6)
Central - 100% interest.
With an estimated mean prospective resource of 18 mmbbl of oil, Mamlambo is a large structure defined on an existing seismic grid, only
8km from the suspended Surprise oil field. An exploration well could target the Lower Stairway Sandstone and the Pacoota Formation,
both of which are proven reservoirs in the Surprise and Mereenie oil and gas fields. Total depth for a potential exploration well could be in
the order of 1,300m.
Orange (EP82(DSA))
Central - 100% interest.
Previous exploration wells at Orange have encountered gas at the shallow Arumbera Sandstone, which is the producing zone at the Dingo
field, some 23km to the south-east. A future exploration well at Orange would target a mean prospective gas resource of 401 PJ from the
Arumbera Sandstone and the deeper Pioneer Sandstone and Areyonga Formation which are volumetrically significant and close to the
existing Dingo pipeline.
Ooraminna (RL3 and RL4)
Central - 100% interest.
After analysing past exploration results at Ooraminna and taking into consideration the potential future costs and risks of exploration,
appraisal and development, increasing regulatory hurdles and costs, and recent government intervention in gas markets, Central will
relinquish its interests in the Ooraminna prospect.
Dingo Deep
Palm Valley Deep
Mereenie Stairway
Orange
Total gas resource
Mamlambo (oil)
PJ
PJ
PJ
PJ
PJ
mmbbl
24.5
37.5
—
284.0
346.0
13.0
34.5
61.5
—
401.0
497.0
18.0
—
—
27.0
—
27.0
—
1. Prospective Resource: As first reported to ASX on 7 August 2020 for Dingo, Palm Valley and Orange, and 10 February 2022 for Mamlambo. The
volumes of prospective resources represent the unrisked recoverable volumes derived from Monte Carlo probabilistic volumetric analysis for each
prospect. Inputs required for these analyses have been derived from offset wells and fields relevant to each play and field. Recovery factors used
have been derived from analogous field production data.
Cautionary statement: the estimated quantities of petroleum that may potentially be recovered by the application of a future development
project(s) relate to undiscovered accumulations. These estimates have both an associated risk of discovery and a risk of development. Further
exploration appraisal and evaluation is required to determine the existence of a significant quantity of potentially recoverable hydrocarbons.
Central confirms that it is not aware of any new information or data that materially affects the information included in those announcements and all
material assumptions and technical parameters underpinning the estimate continue to apply and have not materially changed.
Amadeus, Pedirka and Wiso Basins — Various Areas (see table on page 106)
Central continued to evaluate a number of these areas and has been working to gain Native Title/Aboriginal Land Rights Act clearance and
secure the other necessary approvals in advance of the award of exploration permit status.
Central’s application for exploration permit EPA120 in the NT will not be approved due to overlapping sites of conservation significance.
Southern Georgina Basin, Queensland
Central - 100% interest.
Having reviewed the data acquired from previous activities in these areas and potential future costs and exploration risks, Central will
complete the required rehabilitation work and relinquish its interests in these permits.
Commercial activities during the year focussed on managing Central’s asset portfolio to leverage existing ownership equity to fund
development and exploration growth activities.
Central continued to negotiate new gas sale agreements (GSAs) to replace maturing contracts and gained direct access to the deeper,
higher-priced east coast gas markets for the first time.
In August 2023, Central entered into a Memorandum of Understanding to progress towards a final investment decision for construction of
a helium recovery unit at its Mereenie field, demonstrating the potential of the Amadeus Basin as a world-class helium resource.
Central’s Board has been working with RBC Capital Markets to conduct a strategic review of Central’s asset portfolio, growth strategies and
capital structure. This includes ongoing activities to assess various options to realise value for shareholders.
Despite government intervention in gas markets, there remains strong interest from gas users to secure reliable gas supply, and this has
been reflected in stronger gas prices for new contracts. Two new gas sales agreements for the sale of gas were secured during the year
with:
•
Shell Energy for supply of 0.91 PJ of gas in CY2025; and
•
South 32 for supply of 0.55PJ of gas over two years from 1 January 2023.
The successful new Palm Valley well and Mereenie recompletion program has provided additional developed gas volume for marketing to
customers, and Central is currently negotiating several new supply agreements for future firm supply at attractive prices.
Central has also been able to provide non-contracted gas to customers on an as-available basis and to spot markets, utilising as-available
transportation and market trading arrangements that allow for the sale of non-firm gas from the Mereenie gas field into the east coast
trading hubs, including the Brisbane and Sydney Short Term Trading Markets. This has enabled Central to broaden its customer base and
increase the average price for uncontracted gas, particularly during the winter/spring of 2022 when abnormally high gas prices were
available.
Late in 2022, the Federal Government implemented a price cap of $12/GJ on the sale of gas produced in 2023 under the Gas Market
Emergency Price Order which created a high level of uncertainty in gas markets during the March quarter of 2023. New regulations have
been introduced to extend price controls, although Central is not expected to be directly impacted as its volumes fall below the threshold
and Central only sells gas to Australian customers. Demand for gas in the near and medium term appears strong, with pricing higher than
Central’s historic averages.
Subsequent to the end of the financial year, Central has entered into a Memorandum of Understanding (MOU) with its Mereenie co-
venturers and Twin Bridges LLC (Twin Bridges), a private US company specialising in helium appraisal and production, to progress a helium
recovery unit (HRU) at its Mereenie field in the Northern Territory towards a final investment decision (FID).
The proposed HRU project will target production of up to 60,000 scf of compressed helium gas per day, separating helium from the existing
natural gas produced at Mereenie using proven membrane technology.
Preliminary technical and helium offtake negotiations have been completed indicating solid project economics, leveraging on the existing
gas stream and infrastructure at Mereenie. The compressed helium gas is anticipated to be sold ex-field to a major helium aggregator and
distributor in Australia. The Mereenie JV will share the operating profits from the HRU project on a 50/50 basis with Twin Bridges.
Under the terms of the non-binding MOU, Twin Bridges will design, build, fund and own the HRU, accelerating commencement of helium
production and increasing project value through access to their proven helium processing and marketing expertise.
Additionally, successful production of helium at Mereenie will also demonstrate the potential of the Amadeus Basin as a world-class helium
resource, where Central has a material position in several large sub-salt prospects where relatively-high helium content has previously
been measured.
The only domestic production of helium in Australia is expected to cease when the Darwin LNG plant closes later this year. The proposed
Mereenie HRU project would then be the sole source of domestically-produced helium, helping to satisfy Australia’s strategic need for
helium which is used in many critical health and technology applications.
Central Petroleum is committed to maintaining the highest environmental, social and governance standards across its operations.
As embodied in our core values:
• We put safety first.
• We respect the environment and the communities we work with.
• We value our people and stakeholders.
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.
Central is committed to conducting its operations in an environmentally responsible and sustainable manner aligned with community,
cultural and social expectations. We believe that achieving and maintaining positive environmental outcomes is critical to the success of
our business.
We operate under some of the most stringent environmental regulations in Australia. Our operations are conducted under comprehensive
government-approved Environmental Management Plans (EMPs) in compliance with all relevant Commonwealth and State legislation. The
EMPs typically set out detailed requirements for all aspects of environmental protection, including levels for water and waste
management, air emissions, land disturbance and rehabilitation, soil and flora/fauna conservation including pest and weed control as well
as bushfire prevention.
No fracture stimulation (fracking) activities are conducted in our production or exploration areas.
All personnel engaged by Central are responsible for taking reasonable and practicable steps to identify and mitigate adverse impacts to
the environment while complying with applicable internal controls and environmental legislation.
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.
Internal assessments of compliance with our environmental conditions outlined in the various EMPs over the course of the year identified
over 99% compliance.
One environmental incident was reported to regulators after vegetation in a small area adjacent to the Palm Valley 12 drill site was
impacted by an overspray of formation water, unexpectedly encountered during drilling, from the flare pit. The regulator has confirmed no
breach of regulations or approval conditions occurred. In addition, recent onsite inspections and analysis have confirmed no long-term
damage to the environment as a result of the incident.
Central recognises that climate change is an increasingly significant environmental,
social, and business issue. There is an increasing realisation in the community that
the transition to renewable energy will take longer and be more complex than
initially indicated and will add to cost of living pressures.
There is widespread acknowledgment that natural gas will play a critical role in
providing cleaner, affordable, and reliable energy using existing transmission
infrastructure as we transition to a lower-emission energy future.
We have a social responsibility to contribute towards Australia’s energy security by
providing energy to businesses and residents across the Northern Territory and
eastern states until reliable renewable energy can be introduced. This was
particularly evident in the winter of 2022, when Central supplied 61 TJ of gas into
eastern markets when electricity and gas supplies were critically short.
The residents and businesses of Alice Springs rely on our gas every day to generate
electricity which protects them from central Australia’s soaring summer
temperatures and bitterly cold winter nights. Remote mine sites in the Northern
Territory and Queensland rely on our gas to supply rare minerals to worldwide
markets.
•
•
•
•
Electricity for Alice Springs residents,
businesses, schools and hospitals is
generated from gas from our Dingo gas
field.
Remote mine sites in the Northern
Territory and Queensland rely on our
gas to supply rare minerals to
worldwide markets.
Used for fertiliser manufacturing to
sustain Australian agriculture.
Supplied into the Northern Territory
and Eastern States for residents,
manufacturers and electricity
generation.
We report our greenhouse emissions under the National Greenhouse and Energy Reporting Act 2007 (NGER). In the most recent completed
reporting period, FY2022, our share of scope 1 and 2 emissions across our operations was 28,801 tons of CO2e (51,198 tons in FY2021).
While the aggregate drop primarily reflects the halving of Central’s ownership interests from October 2021, on a per unit basis, our
emissions intensity dropped from 4.99 kgCO2e/GJe in FY2021 to 4.59 KgCO2e/GJe in FY2022 due to a higher proportion of production from
the lower-emissions Palm Valley field.
We have invested in several initiatives to reduce our emissions, including an $8 million flare gas recovery project at Mereenie. The new
flare gas compressor is expected to be installed before the end of 2023, and is expected to reduce flare gas emissions at Mereenie by more
than 25% and overall emissions across our three production 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.
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.
At Central, the safety of our employees, contractors and the community are paramount.
During the year, over 324,926 hours were worked, with two recordable injuries, resulting in a Total Recordable Injury Frequency Rate
(TRIFR) at 30 June 2023 of 6.1.
Central is committed to protecting workers and other persons against harm to their health, safety and welfare through the elimination or
minimisation of risks arising from our operations.
Central works closely with the communities in which it operates. We rely on the support of our local communities, landowners, and other
stakeholders, and we seek to provide employment and business opportunities to our local communities.
In the Northern Territory, for example:
•
•
•
•
40% of our staff live locally.
25% of our staff are indigenous.
Central paid over $2.6M of royalties and fees to the Northern Territory and Central Land Council in FY2023.
Central and partners spent over $3.0M with local contractors and businesses in FY2023.
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.
Net proved & probable (2P) oil and gas reserves were 75.0 PJe at 30 June 2023.
Oil
Proved reserves (1P)
Proved plus probable reserves
(2P)
mmbbl
mmbbl
Contingent Resources (2C)
mmbbl
0.37
0.41
0.05
Gas
Proved reserves (1P)
Proved plus probable reserves
(2P)
Contingent Resources (2C)
PJ
PJ
PJ
57.99
70.96
187.49
(0.03)
(0.03)
—
(4.01)
(4.01)
—
—
—
—
6.78
5.88
0.34
0.38
0.05
60.76
72.83
(2.28)
185.21
0.32
0.36
—
47.23
56.80
—
1
All developed and undeveloped 1P and 2P reserves are located in the Amadeus Basin geographical area.
Mereenie, oil
Proved reserves (1P)
Proved plus probable reserves (2P)
Contingent Resources (2C)
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)
mmbbl
mmbbl
mmbbl
PJ
PJ
PJ
PJ
PJ
PJ
PJ
PJ
PJ
Note: Estimates may not arithmetically balance due to rounding.
0.37
0.41
0.05
30.46
39.21
45.60
11.29
12.73
6.84
16.23
19.02
(0.03)
(0.03)
—
(1.73)
(1.73)
—
(1.68)
(1.68)
—
(0.60)
(0.60)
—
—
—
—
—
—
2.99
2.36
(2.28)
3.79
3.52
135.05
—
—
135.05
The information contained in this Reserves and Resources Statement is based on, and fairly represents, information and supporting
documentation reviewed by Mr Kevan Quammie who is a full-time employee of Central Petroleum holding the position of Exploration and
Development Manager. Mr Quammie holds an M.Sc. Petroleum and Natural Gas Engineering from the Pennsylvania State University, is a
member in good standing of the Society of Petroleum Engineers, is qualified in accordance with ASX listing rule 5.41. and has consented to
the inclusion of this information in the form and context in which it appears.
0.02
0.02
—
13.53
16.03
—
0.34
0.38
0.05
28.73
37.48
45.60
12.61
13.41
4.56
19.42
21.94
The reserves and resources information in this document relating to:
• the Palm Valley and Dingo fields, as at 30 June 2023, were first reported to ASX on 27 July 2023, 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. (“NSAI”), holding the position of Senior Vice President;
• the Mereenie field were first reported to ASX on 27 July 2023, and are based on, and fairly represents information and supporting
documentation reviewed by Mr Kevan Quammie who is a full-time employee of Central Petroleum Limited holding the position of
Exploration and Development Manager and is a member in good standing of the Society of Petroleum Engineers; and
• the Range Gas Project resources were first reported to the market on 20 August 2019 and are based on, and fairly represent information
and supporting documentation reviewed by Mr John Hattner who is a full-time employee of NSAI, 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.
Central Petroleum recognises that the effective management of risks inherent to our business is vital to delivering our strategic objectives,
continued growth and success. We are committed to managing risks in a proactive, robust, and effective manner, to help achieve our
objectives.
Our risk management process is designed to recognise and manage risks that have the potential to materially impact on Central’s business
objectives. This process is aligned to the international standard ISO31000 for risk management and assesses potential risks across our
business. In managing these risks, we consider impacts on the health and safety of our employees, the environment and communities in
which we operate, our financial stability, our reputation and legal and compliance obligations.
Climate change concerns are influencing a fast-changing business landscape, with emerging policies and regulations presenting both risks
and opportunities for our existing assets and growth prospects as Australia transitions towards a lower-carbon future. Our risk
management framework provides an integrated and coordinated approach to the management of climate change risks across the business.
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.
Social and Legal License to Operate
Failure to meet stakeholder expectations can
lead to opposition and a decline in support for
both our operational activities and future
growth opportunities.
Central proactively maintains and builds our social
license to operate through the application of our
values, effective stakeholder engagement strategies,
and our regulatory compliance framework.
A significant or continuous departure from
national or local laws, regulations or approvals,
or the introduction of new laws and
regulations may result in negative social,
cultural and reputational impacts, loss of
license to operate and could impact our ability
to operate or pursue our growth strategy.
Violation of laws and regulations may expose
Central to fines, sanctions, and civil suits, and
negatively impact our reputation.
We have a robust framework in place to support our
regulatory and compliance obligations and we
continue to strengthen our regulatory compliance
framework and supporting tools.
We proactively maintain open dialogue with
governments, regulators and stakeholders within
jurisdictions in which we operate.
Our fraud and corruption framework aims to
prevent, detect, and respond to unethical behaviour.
It incorporates policies, procedures, and training to
ensure activities are conducted ethically.
Our business performance is
underpinned by our social
license to operate, that
requires compliance with
legislation and the
maintenance of a high
standard of ethical behaviour
and social responsibility.
Our business activities are
subject to extensive
regulation and increasingly
costly government policy.
Failure to comply may impact
our license to operate.
Stakeholders have evolving
expectations of social
responsibility and ethical
decision making, which
exceed regulatory
requirements.
Growth
Our future growth depends
on our ability to identify,
acquire, explore, appraise
and develop resources.
The inability to identify and commercialise
growth opportunities, or realise their full value,
may result in a loss of shareholder value.
Unsuccessful exploration and renewal of
upstream resources may impede delivery of
our strategy.
Our ability to successfully
deliver value adding projects
is also critical.
Central is exposed to market and industry
conditions - some beyond our control, which
may impact project delivery and lead to cost
overruns or schedule delays when developing
and executing our portfolio of capital projects.
Oil and Gas Reserves
Commercialisation of
hydrocarbon reserves is a key
contributor to our long-term
success.
Uncertainty in hydrocarbon reserve estimation
and the broad range of possible recovery
scenarios from existing resources could have a
material adverse effect on our operations and
financial performance.
We engage experienced, skilled personnel to identify
and progress a suite of commercially attractive and
sustainable opportunities that complement our
existing assets, enable portfolio diversity and
optimise our commercial position.
Exposure to reserve depletion is addressed through
our exploration strategy. We continue to analyse
existing acreage for exploration drilling prospects.
We utilise an established project management
framework which is supported by skilled and
experienced personnel to govern and deliver major
projects.
Our reserve and resource estimates are prepared in
accordance with the guidelines set forth in the 2018
Petroleum Resources Management System (PRMS).
We proactively analyse reservoir performance and
undertake comprehensive production and economic
modelling to determine the most likely outcomes
across our fields. We engage independent experts
periodically to provide reserve estimates.
Climate Change
Climate change is impacting
the way that the world
produces and consumes
energy.
Oil and gas produced by
Central are fossil fuels, the
production and consumption
of which emit greenhouse
gases.
Demand for oil and gas may subside over the
longer-term, impacting demand and pricing as
lower carbon substitutes take market share.
Global climate change policy remains uncertain
and has the potential to constrain Central’s
ability to create and deliver stakeholder value
from the commercialisation of hydrocarbons.
Introduction of taxes or other charges
associated with carbon emissions may have an
adverse impact on Central’s operations,
financial performance and asset values.
It is believed that climate
change may result in more
extreme weather in the
future.
There may be increased frequency of extreme
weather events such as severe storms, floods,
drought and bushfires which could damage
Central’s production infrastructure and
interrupt Central’s operations.
We are focused on ensuring our business is robust in
a potentially carbon constrained market and engage
proactively with key industry and government
stakeholders. Our future is predominantly focused
on supplying natural gas as a transitional fuel which
could see demand for gas increase in the medium
term as part of the transition to a clean energy
future compared to other energy sources.
Central also seeks value accretive opportunities to
reduce carbon emissions and/or utilize or sequester
carbon, with both Palm Valley and Mereenie
potential candidates for carbon capture and storage
(CCS).
Central has opportunities to diversify its reliance on
hydrocarbons by targeting valuable non-
hydrocarbon gases such as helium and naturally
occurring hydrogen which exist in some of its
production and exploration permits.
Central’s production assets are located in arid
regions not prone to cyclones, flooding or
uncontrolled bushfires. Central maintains insurance
to cover weather related risks.
Community
Our proactive engagement
and support of local and
indigenous communities is at
the core of how we operate.
Health and Safety
Health and Safety is at the
heart of all activities and
decisions at Central.
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.
Our interactions with, and decisions involving
landholders, traditional owners, suppliers and
the community fails to attract and maintain the
continued support of the communities in which
we operate.
We work in conjunction with our key stakeholders
and have established programs to support and assist
the communities in which we operate through
donations, sponsorships, local procurement, training
and providing ongoing local employment and
business opportunities.
Health and Safety incidents or accidents may
adversely impact our people, the communities
in which we operate, our reputation and/or
our licence to 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.
Failure to establish and develop sufficient
capability and capacity to support our
operations may impact achievement of our
objectives.
We are focussed on securing and developing the
right people to support the operation and
development of our portfolio of assets and
opportunities. We also proactively engage
contractors to supplement any short-term gaps in
capability and capacity to support the execution of
our business plans.
Operating
The production and delivery
of hydrocarbon products
safely and reliably are key
elements of our operational
and financial performance
and directly impact
shareholder returns.
Reservoir / field performance is subject to
subsurface uncertainty. The actual
performance could vary from that forecasted,
which may result in diminished production and
/or additional development costs.
We continually monitor field performance and
schedule production optimisation and development
activities to extract maximum value from the field
and to mitigate any potential reservoir under-
performance.
Our facilities are subject to hazards associated
with the production of gas and petroleum,
including major accident events such as spills
and leaks which can result in a loss of
hydrocarbon containment, diminished
production, additional costs, environmental
damage or harm to our people, reputation or
brand.
Embedded within our operational practices is a
framework of controls which enable the
management of these risks. We have in place asset
integrity management processes, inspections,
maintenance procedures and performance standards
across all activities and infrastructure to maximise
reliable and safe operations.
Central maintains insurance in line with industry
practice considered sufficient to cover normal
operational risks. However, Central is not insured
against all potential risks because not all risks can be
insured cost effectively. Insurance coverage is
determined by the availability of commercial options
and cost/ benefit analysis, considering Central’s risk
management program.
Environment
Our environmental
performance underpins our
licence to operate.
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.
We work closely with our joint venture partners to
achieve mutually beneficial outcomes.
Joint Ventures
Although we operate most of
the tenements we hold, we
are dependent on technical
and commercial alignment
with our joint venture
partners.
Access to Infrastructure
Misalignment between joint venture partners,
or failure to honour financial commitments,
can lead to scarcity of available capital and
may impact the prioritisation of exploration,
development or production opportunities. This
can lead to delayed approvals or forfeited
tenure, which may impact Central’s growth
strategy.
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.
Financial
Our financial strength and
performance underpins our
strategy and future growth.
Insufficient liquidity to meet financial
commitments and fund growth opportunities
could have a material adverse effect on our
operations and financial performance.
Our revenue is from the sale
of hydrocarbons. This
underpins Central’s financial
performance.
Central is exposed to USD commodity price
variability with respect to crude oil sales which
are impacted by broader economic factors
beyond our control.
Central is exposed to gas commodity prices
with respect to gas sales, all of which are to the
Northern Territory and Australian east coast
markets. In addition to normal demand and
supply forces, gas prices in these markets are
subject to risk of Government intervention,
including the Australian Domestic Gas Supply
Mechanism and Mandatory Code of Conduct.
We have a robust expenditure management and
forecasting process which is monitored against a
Board approved budget to ensure capital is allocated
in accordance with the company’s strategy. We
actively manage debt and other funding sources to
ensure the business is appropriately capitalised to
sustain ongoing operations and growth plans. We
also actively seek partnering opportunities to share
risks and assist in funding key activities on a project-
by-project basis.
Oil revenue represented less than 9% of
consolidated sales revenue in FY2023.
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.
Central receives an automatic exemption from
mandated gas price caps from December 2023 as its
level of production falls below eligibility thresholds
and its gas supplies are only to domestic markets.
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.
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.
Central’s information and operational
technology systems may be subject to
intentional or unintentional disruption (e.g.
cyber security attack) which could impact our
ability to reliably supply customers.
We continuously assess and determine access
permissions to critical information or data, whilst
consolidating, simplifying, and automating security
controls.
Our exposure to cyber risk is managed by a proactive
and continuing focus on system controls such as
firewalls, restricted points of entry, multifactor
authentication, multiple data back-ups and security
monitoring software. We are continuing to embed a
cyber-safe culture across Central.
We ensure that appropriate insurance is in place to
mitigate the impact of any extended business
interruption. The Range coal seam gas project in the
Surat Basin is increasing the geographical
diversification of our business. We are also
investigating other new ventures outside of the
Amadeus Basin.
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.
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 2023.
The names of the Directors of the Company in office during the financial year and until the date of this report are set out below. Directors
were in office for this entire period unless otherwise stated.
Mr Michael (Mick) McCormack (Chair)
Mr Leon Devaney (Managing Director)
Mr Stuart Baker (resigned 30 August 2022)
Mr Stephen Gardiner
Mr Troy Harry (commenced 1 September 2022)
Ms Katherine Hirschfeld AM
Dr Agu Kantsler
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.
No dividends were paid or declared during the financial year (2022: $Nil). No recommendation for payment of dividends has been made.
The operating and financial highlights for the financial year were:
•
•
The Group added an additional 5.9 PJ of Proved and Probable (2P) gas reserves at 30 June 2023, representing an increase of 8%
(before production) to 75 PJe, reflecting drilling and production results at Palm Valley and updated Dingo reservoir modelling.
The Palm Valley 12 well was successfully tied into the Palm Valley processing facilities and flowed gas to market from late
November 2022 at greater than 10 TJ per day.
• New gas sales agreements for the sale of gas were secured with:
o
o
Shell Energy for supply of 0.91 PJ of gas in CY2025; and
South 32 for supply of 0.55 PJ of gas over two years from 1 January 2023.
Average sales prices were up 17% on FY2022 at $7.90 / GJe.
Annual revenue from hydrocarbon sales of $38.2 million was up 12% from FY2022 on a like for like basis.
In August 2023, agreement was reached to progress towards a final investment decision for construction of a helium recovery unit
at Mereenie, demonstrating the potential of the Amadeus Basin as a world-class helium resource.
•
•
•
A detailed review of the operating and financial performance for the year ended 30 June 2023, including principal risks is provided from
pages 3 to 25 of this Annual Report.
The financial position and performance of the Group was particularly affected by the following events and transactions during the year
ended 30 June 2023:
•
•
•
•
A new production well was drilled and commissioned at Palm Valley, significantly increasing gas production from late November
2022.
Drilling and production results at Palm Valley and updated Dingo reservoir modelling led to an additional 5.9 PJ of new 2P gas
reserves being recorded.
The debt facility was increased by two separate tranches of $6 million which are available to fund production growth opportunities
across Central’s Amadeus Basin gas projects.
Doubts surrounding the ability of a joint venturer to fund its obligations under various farmin arrangements led to recognition of an
impairment charge of $3 million. The relevant joint venturers are reconsidering the structure, timing, and funding of the sub-salt
exploration program.
There were no other significant events that are not detailed elsewhere in this Annual Report.
In August 2023, the Group reached agreement to progress towards a final investment decision for construction of a helium recovery unit at
Mereenie, demonstrating the potential of the Amadeus Basin as a world-class helium resource.
No other significant matters or circumstances have arisen between 30 June 2023 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.
Production enhancement
Two new development wells are being considered by the Mereenie joint venture and could be drilled by mid-2024 to boost production
capacity at Mereenie for supply into strong gas markets.
Exploration
A significant, three well sub-salt exploration campaign in the southern Amadeus Basin is planned, targeting high-value helium, naturally
occurring hydrogen and natural gas resources. The structure, timing and funding of the exploration program are being reconsidered as
committed farm-out funding is now unlikely to be forthcoming. Central is considering alternative arrangements for the permits and wells,
including negotiation for deferral of permit commitments, new farm-outs, sourcing of additional funding or, alternatively, relinquishment
of the permits.
Other proposed near-term exploration activity includes seismic acquisition at the large Zevon sub-salt lead to identify a possible site for an
exploration well. Central is also planning to advance an oil exploration well at Mamlambo, subject to funding availability.
Helium Recovery Unit
Central and its partners at Mereenie will work with Twin Bridges, a private US company specialising in helium appraisal and production to
achieve the necessary design, engineering, commercial and financial milestones required to reach FID for the construction of a helium
recovery unit (HRU) at Mereenie. If the project proceeds, Twin Bridges will design, build, fund and own the HRU plant which will be
integrated with the existing Mereenie gas processing facility operated by Central, targeting production of up to 60,000 scf of compressed
helium gas per day.
Commercial
Demand for gas is expected to remain strong through FY2024, and Central expects to be able to commit to new gas supply contracts at
higher pricing than in previous periods as existing contracts mature.
Further information on these activities is included from pages 1 to 25 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.
Independent Non-executive Chair
Mr McCormack was appointed as a director on 1 September 2020 and has over 38 years’ experience in the energy
infrastructure sector in Australia and his career has encompassed all aspects of the sector, including commercial
development, design, construction, operation and management of most of Australia’s natural gas pipelines and gas
distribution systems. His experience extends to gas-fired and renewable power generation, gas processing, LNG and
underground storage.
Mr McCormack is a former Managing Director and CEO of APA Group and former Director of Envestra (now Australian
Gas Infrastructure Group), the Australian Pipeline Industry Association (now Australian Pipelines and Gas Association)
and the Australian Brandenburg Orchestra. He is a non-executive director at Origin Energy and Austal Limited and a
director of the Clontarf Foundation and the Australian Brandenburg Orchestra Foundation and a Fellow of the
Australian Institute of Company Directors.
Directorships of other listed companies in the last three years: Director of Austal Limited from September 2020 and
Director of Origin Energy Limited from December 2020.
Managing Director and Chief Executive Officer
Mr Devaney has over 20 years of commercial and finance experience within the Australian oil and gas sector and holds
an MBA and BSc (Finance) from the University of Southern California, USA.
He joined Central Petroleum in 2012 and has been responsible for commercial, finance and business development
activities in various senior roles. He was instrumental in negotiating the Mereenie acquisition from Santos in 2015 and
the Palm Valley and Dingo Gas Field acquisition from Magellan Petroleum in 2014, as well as structuring the winning
application for ATP2031 (Range Gas Project) in 2018. Mr Devaney has been a director since 14 November 2018 and was
appointed Chief Executive Officer, effective February 2019, after serving as Acting CEO since July 2018.
Prior to joining Central Petroleum, he worked at QGC and played a pivotal role in its growth from a small cap gas
exploration company into a multi-billion-dollar takeover target by the BG Group in 2008. He continued with BG
following the QGC takeover, where he served as General Manager, Gas and Power, responsible for the domestic gas
and electricity portfolio.
Prior to QGC, Mr Devaney held senior roles at Deloitte in the Corporate Finance Advisory Group where he was active in
structuring and implementing commercial and financing transactions for major energy and infrastructure projects
throughout Australia.
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.
While at Oil Search, Mr Gardiner 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, Mr Gardiner held senior corporate finance roles at major multinational companies including CSR
Limited and Pioneer International Limited. Mr Gardiner has particular strength in capital management and funding,
both debt and equity, having raised many billions of dollars, including via structured financings such as working on the
US$15 billion PNG LNG Project financing, the largest such financing ever undertaken at the time.
Directorships of other listed companies in the last three years: ioneer Ltd from 25 August 2022.
Non-executive Director
Mr Harry has been a director of Central Petroleum Limited since 1 September 2022 and is a professional investor with
interests in many ASX listed companies, as well as private businesses and property. He formerly had a career in
stockbroking and funds management and was the founder of Trojan Investment Management Pty Ltd.
Mr Harry is currently a director of numerous private entities. He has not held any other ASX directorships in the last 3
years.
Through his associated entities, Mr Harry is a substantial shareholder in Central Petroleum Limited.
Independent Non-executive Director
Ms Hirschfeld was appointed as a director on 7 December 2018 and is a highly regarded non-executive director, having
served on company boards listed on the ASX, NZX and NYSE, as well as government and private company boards. She is
currently the Chair of Powerlink and a board member of Spark Infrastructure RE Limited, its subsidiaries and related
entities (which includes the Boards of SA Power Networks and Victoria Power Networks (Powercor and CityPower)) and
Sims Limited.
Ms Hirschfeld has also been a board member and President of UN Women National Committee Australia and non-
executive director of Energy Queensland, Tox Free Solutions, InterOil Corporation, Broadspectrum, Snowy Hydro and
Queensland Urban Utilities.
Previously she had leadership roles with BP in oil refining, logistics, exploration and production located in Australia, UK
and Turkey.
Ms Hirschfeld was recognised in the AFR/Westpac 100 Women of Influence 2015, by Engineers Australia as one of
Australia’s Top 100 Most Influential Engineers 2015 and as an Honorary Fellow in 2014. She is a member of Chief
Executive Women and a Fellow of the Australian Institute of Company Directors and the Academy of Engineering and
Technology. She is also an executive mentor/coach with Merryck & Co.
In 2019 Ms Hirschfeld was appointed a Member of the Order of Australia (AM) for significant service to engineering, to
women, and to business.
Directorships of other listed companies in the last three years: Director of Sims Limited from 1 September 2023.
Independent Non-executive Director
Dr Kantsler has been a director of Central Petroleum Limited since 15 June 2020 and is one of Australia’s most
respected and experienced petroleum exploration executives, having led Woodside Petroleum’s world-wide
exploration, business development and geotechnical activities as Executive Vice President Exploration and New
Ventures from 1995 to 2009. He also led Woodside’s Health, Safety and Security Department during 2009 and 2010.
Prior to joining Woodside, Dr Kantsler worked for Shell in various international locations. He has served as Director and
Chairman of the Australian Petroleum Production & Exploration Association (APPEA) and President of the Chamber of
Commerce and Industry WA.
Dr Kantsler is Managing Director of Transform Exploration Pty Ltd, a Non-Executive Director of ASX-listed Suvo Strategic
Minerals Ltd, and a former Director of Oil Search Limited.
Directorships of other listed companies in the last three years: Director of Suvo Strategic Minerals Ltd from
5 September 2023.
Mr White is an experienced oil and gas lawyer in corporate finance transactions, mergers and acquisitions, equity and
debt capital raisings, joint venture, farmout and partnering arrangements and dispute resolution. He has previously
held senior international based positions with Kuwait Energy Company and Clough Limited.
The numbers of meetings of the Company’s board of directors and of each board committee held during the financial year, and the
numbers of meetings attended by each Director were:
Stuart Baker3
Leon Devaney
Stephen Gardiner
Troy Harry4
Katherine Hirschfeld AM
Agu Kantsler
Michael McCormack
3
12
12
9
12
12
12
3
12
12
9
12
12
11
0
—
4
4
4
—
4
0
4
4
4
4
4
—
—
4
—
4
4
4
0
4
4
4
4
4
4
1
—
4
4
—
5
5
1
5
5
4
5
5
5
0
—
30
30
30
30
30
0
30
26
29
26
28
24
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 Stuart Baker resigned as Director on 30 August 2022.
4 Troy Harry was appointed as Director on 1 September 2022.
(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) There were no unissued ordinary shares of Central Petroleum Limited or interests under option at the date of this report.
(c) No shares were issued by Central Petroleum Limited during or since the end of the year on the exercise of options.
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. Internal reviews of compliance with the environmental conditions outlined in applicable
Environmental Management Plans over the course of the year identified over 99% compliance.
During the financial year, the Group paid premiums to insure Directors and officers of the Group. The contracts include a prohibition on
disclosure of the premium paid and nature of the liabilities covered under the policy.
A copy of the Auditor’s Independence Declaration as required under section 307C of the Corporations Act 2001 is set out on page 49.
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.
During the year the Company engaged the auditor, PricewaterhouseCoopers (PwC), on assignments additional to its 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
$
$
14,280
47,512
61,792
9,588
10,579
20,167
Dear Shareholders,
LTIP
FY2023 marks the end of the final performance period for the
discontinued Long Term Incentive Plan (LTIP). The LTIP’s
Absolute TSR performance for the three years from 1 July 2020
to 30 June 2023 failed to achieve the minimum growth hurdle of
10% pa. Whilst disappointing in absolute terms, Central’s share
price performance over this period was relatively strong when
compared to our peers within the sector. The Relative TSR
placed Central at the 59th percentile compared to its peers,
resulting in 30% of rights vesting for this three year performance
period. The Board has discretion to retest performance of these
hurdles at 31 December 2023.
As in 2022, the independent Directors sacrificed a portion of
their fees to acquire share rights to increase their alignment
with shareholders.
To assist readers of this report to understand the actual
remuneration which the senior executives have received this
year, we have again included a Realised Remuneration table
(refer Table 1 in section J of the Remuneration Report).
With the LTIP coming to an end this year and legacy executive
options lapsing ‘out-of-the-money’, our remuneration structure
is becoming less complex and more directly linked to
performance. And while incentive awards this year were lower
than in previous years, we believe that the appropriate structure
is in place to drive higher performance across the organisation,
and these results will ultimately be shared with our
shareholders.
Michael (Mick) McCormack
Remuneration and Nominations Committee Chair
The challenges of COVID seem a distant memory, however the
resulting ripples from the social and economic disruption
continue to impact our ability to maintain a skilled and
productive workforce.
The return of overseas workers has alleviated some of the salary
pressures, but this has been countered by demands to soften
the impacts of the rising cost of living.
While our field-based staff can’t participate in the work-from-
home revolution, the undercurrent for increased flexibility
remains throughout the labour markets. The battle remains to
retain staff in a very competitive market.
It is in the context of these changing labour markets that we
maintain a remuneration structure that seeks to balance
expectations with performance and reward through a
combination of competitive fixed remuneration and
performance-based incentives.
Fixed remuneration
To counter rising cost of living pressures and to remain
competitive, we increased remuneration across the Company by
approximately 4.5% for FY2023, along with the 0.5% increase in
compulsory superannuation contributions. Average salaries will
rise by approximately 4% from July 2023 plus the 0.5% increase
in superannuation contributions.
Short-term incentives
Staff, other than executives, participated in the Short Term
Incentive Plan (STIP), which targets near-term performance
through the achievement of personal and corporate objectives
over the year, providing an opportunity to earn from 10% to
30% of base remuneration, depending on role and responsibility.
The FY2023 STIP award reflected a strong operating
performance from the smaller asset base, with capital
management performance exceeding its stretch target and
operating cost control targets achieved. The STIP award would
have been higher, but for a lack of progress on commercial
initiatives and delays and cost overruns to our exploration and
development programs, which also impacted sales volumes.
As a result, personnel were entitled to an average 51% of their
maximum STIP incentive for the year, somewhat lower than in
previous years.
With the uncertainty of the ongoing strategic review process, we
extended a retention incentive to a handful of key operational
personnel in an attempt to avoid the loss of key operational
capability until the outcome of the review is known.
Executive incentives
Our executive team participated in an incentive program that
integrates short and long-term components, with performance
measured against the same corporate KPI targets as for the STIP.
Of the maximum available in FY2023, 45% was awarded, with
one-third to be paid this year and the balance converting into
share rights vesting over the next three years.
This Remuneration Report for the year ended 30 June 2023 (FY2023) 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
M
Directors and Key Management Personnel (KMP)
Remuneration Overview
Remuneration Policy
Remuneration Consultants
Long Term Incentive Plan – Employee Rights Plan (LTIP)
Executive Share Option Plan (ESOP)
Executive Incentive Plan (EIP)
Short Term Incentive Plan (STIP)
Key operational employee retention incentive
Realised Remuneration
Remuneration Details – Statutory Tables
Executive Service Agreements
Non-Executive Director Fee Arrangements
The Directors and key management personnel of the Consolidated Entity during the year and up to signing date of the Annual Report were:
Mr Michael (Mick) McCormack
Mr Leon Devaney
Mr Stuart Baker
Mr Stephen Gardiner
Mr Troy Harry
Ms Katherine Hirschfeld AM
Dr Agu Kantsler
Independent Non-executive Chair
Managing Director and Chief Executive Officer
Independent Non-executive Director (resigned 30 August 2022)
Independent Non-executive Director
Non-executive Director (commenced 1 September 2022)
Independent Non-executive Director
Independent Non-executive Director
Mr Ross Evans
Mr Damian Galvin
Dr Duncan Lockhart
Mr Jonathan Snape
Mr Daniel White
Chief Operations Officer
Chief Financial Officer
General Manager Exploration (resigned 31 August 2022)
Chief Commercial Officer (resigned 20 January 2023)
Group General Counsel and Company Secretary
Central’s remuneration strategy is designed to attract, motivate and retain high performing individuals and is linked to the Group’s
objectives to build long-term shareholder value. In doing so, Central adopts a pay for performance culture which is balanced by a fair and
equitable approach to the retention and motivation of its team. The current remuneration strategy incorporates the following features:
Linking internal strategies to improved shareholder value through achievement of appropriate KPIs.
a.
b. Group-wide performance incentives to drive high performance.
c. Providing key executives with incentives which provide rewards for achievement of annual KPI targets, payable through a
combination of cash and deferred equity to provide longer-term alignment with shareholders.
d. Adjusting to remuneration best practice and movements in relevant labour markets.
Salary increases in FY2023
An average 4.5% pay rise applied to eligible employees for FY2023 and compulsory superannuation
contributions increased from 10% to 10.5%. As at 1 July 2023, salaries for eligible employees will rise, on
average, by 4% for FY2024. In addition, employees will benefit from the statutory increase in compulsory
superannuation contributions from 10.5% to 11%.
Short Term Incentive Plan
(STIP)
Achievement of Group-wide corporate and individual KPIs resulted in payment of an average 51% of the
maximum STIP to eligible employees. Refer Section H of this report.
Executive Incentive Plan
(EIP)
Achievement of Group-wide corporate KPIs resulted in an award of 45% with 1/3 of the awarded value
being payable as cash (or equity) and 2/3 being Share Rights to vest progressively over the next 3 years.
Refer Section G of this report.
Vesting of Share Rights
previously granted under
the Long Term Incentive
Plan (LTIP)
The vesting rate for Share Rights issued under the Long Term Incentive Plan for the three year period
ending 30 June 2023 was 29.935%. This may, at the Board’s discretion, be eligible for retesting at
31 December 2023. Refer Section E of this report.
The remuneration policy of the Group 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 Group’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. From FY2022, executives participate in an Executive Incentive Plan (EIP) that combines both short
term annual KPIs and a longer-term, deferred equity-based component (refer Section G below).
Other personnel participate in a Short Term Incentive Plan (STIP), which provides an incentive linked to achievement of corporate and
personal KPIs (Section H), and are also eligible for an annual grant of equities to a value of $1,000 with a three year vesting period
(Section E).
For periods up to and ending on 30 June 2023, the remuneration of directors and executives consisted of the following key elements:
Non-executive directors:
Fees including statutory superannuation;
1.
2. Up to 25% sacrifice of FY2023 base fees (inclusive of superannuation but excluding committee fees) in order to receive an
equivalent value in the form of Share Rights issued under the Group’s Employee Rights Plan; and
3. No participation in short or long term incentive schemes.
Executives, including executive directors:
1. Annual salary and non-monetary benefits including statutory superannuation; and
2. Participation in the Executive Incentive Plan (EIP), vesting over a 4 year period.
In previous years, executives have participated in various long term incentive plans, with the vesting periods for some of these plans
extending through FY2023.
The balance of fixed and maximum at risk remuneration for executives for FY2023 is summarised as follows:
CEO
45% fixed remuneration
18% at risk
36 % at risk (EIP Service Rights)
Other Executives
56% fixed remuneration
15% at risk
30% at risk (EIP Service
Rights)
Salary
EIP short term
EIP over three years
The following table summarises the key performance and shareholder wealth metrics in relation to the outcomes of the STIP, LTIP and EIP
over the last five years:
Financial performance
Operating revenue
Profit/(loss) after income tax
Underlying EBITDAX1
Shareholder wealth
Share price at year end
Absolute TSR (3 years)
Relative TSR (3 years)
Incentive awarded
STIP
LTIP
EIP
$ million
$ million
$ million
$/share
% growth pa
Percentile rank
% of maximum
% of maximum
% of maximum
59.36
(14.53)
22.19
$0.135
15.5%
88th
82%
75%
N/a
65.05
5.41
25.01
$0.081
(16.1%)
25th
67%
nil
N/a
59.83
0.25
26.09
$0.117
(9.1%)
57th
67%
31.5%
N/a
42.15
21.32
16.75
$0.110
(4.6%)
69th
62.75%
43%
62.5%
39.26
(7.96)
15.75
$0.053
(13.1%)
56th
51.0%
29.9%
45.0%
1 Underlying EBITDAX is underlying Earnings before Interest, Tax, Depreciation, Amortisation, Impairment and Exploration costs and profit
on disposal of interests in producing properties. Refer to the Operating and Financial Review for further information.
In the past five years, Central has recorded strong revenue and underlying EBITDAX results as expansion programs at the Group’s Amadeus
Basin oil and gas fields enabled increased production into new markets with the opening of the Northern Gas Pipeline in early 2019. In
FY2022, the partial sale of the Company’s producing oil and gas assets was completed, recognising a $36.6 million profit on the sale and
providing funds to pay-down debt and fund new exploration and development activity. STIP awards from FY2019 to FY2022 have reflected
this success, paid as a combination of cash, equity and deferred equity over those years. The FY2023 STIP/EIP award reflected a strong
operating performance from the smaller asset base, with capital management performance exceeding its stretch target and operating cost
control targets achieved. The STIP/EIP award in FY2023 however, would have been higher, but for a lack of progress on commercial
initiatives and delays and cost overruns to the Company’s exploration and development programs which also impacted sales volumes.
The LTIP awards over recent years have followed the Group’s 3 year share price performance, resulting in a relatively high award in FY2019
as the share price reflected increasing production and announcement of the Range gas project. COVID-related market weakness impacted
the FY2020 award, with only participants in the $1,000 Exempt Plan LTIP receiving any value. Volatile equity and energy markets in FY2021,
FY2022 and FY2023 have seen a decline in share price in absolute terms, but Central’s shares have performed relatively well against those
of its peers, resulting in a partial vesting of LTIPs for participants in those years.
The performance of the Group 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 2022 review of remuneration. Guerdon Associates were engaged to provide
market information relating to a retention strategy in the context of the Strategic Review, as well as providing a determination on the
relative total shareholder return performance hurdle relating to the LTIP’s performance period ending 30 June 2023. Guerdon Associates
also provided clarification on matters dealing with treatment of dividends and returns of capital as they relate to equity incentives.
The performance-linked LTIP was discontinued after FY2021 and the final year for measuring share price performance for these legacy
plans was FY2023.
The LTIP has previously been a major component of the incentive framework for senior staff, and in developing the Employee Rights Plan,
the Board focused on creating strong linkages between shareholder value as measured by shareholder returns and remuneration.
Consequently, vesting conditions have been weighted equally between relative shareholder return and absolute shareholder return over a
three-year period, aligning reward with share performance against peer companies and also with absolute share price growth.
The Group’s Employee Rights Plan was last approved by shareholders in November 2022 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 last of which was the
three-year period ending 30 June 2023.
FY2023 Performance
The following table details the percentage of Share Rights in respect of the three-year performance period ending 30 June 2023 which will
vest (Vesting Percentage) as determined by the performance conditions, based on the 20-day VWAP prior to 30 June 2023 of $0.0578. The
benchmark share price at the start of the performance period was $0.0882:
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%
Relative TSR – E&P2
(50% weighting)
Company's TSR relative to a specific group
of exploration and production companies3
(determined by the Board within its
discretion) calculated as at vesting date
Company’s Relative TSR
76th percentile and above
Share Rights
Vesting
100%
From 51st to 75th percentile
50% to 99%
(59.87%)
Below 51st percentile
0%
1 Total shareholder return (i.e. growth in share price plus dividends reinvested).
2 Exploration and Production.
3 The peer group of companies for the three-year performance period ended 30 June 2023 is: Armour Energy Limited, Blue Energy Limited, Buru Energy Limited,
Carnarvon Energy Limited, Cooper Energy Limited, Comet Ridge Limited, Empire Energy Group Limited, FAR Limited, Galilee Energy Limited, Horizon Oil Limited, Icon
Energy Limited, State Gas Limited, Strike Energy Limited, Triangle Energy Global Limited, Vintage Energy Limited and 3D Oil Limited.
Key terms and vesting conditions
For the purposes of determining the number of Share Rights to vest, the Company’s absolute TSR and relative TSR are calculated as at the
end of the performance period. The Vesting Percentage for each is determined by reference to the hurdle bandings set out in the above
tables. The Share Rights for each applicable hurdle are then multiplied by the Vesting Percentage achieved for that hurdle to determine the
total number of Share Rights which vest on the vesting date. Vested Share Rights may then be exercised in accordance with the Employee
Rights Plan Rules. Each vested Share Right can be exercised at the rate of one Share Right for one Ordinary Share in the Company.
Employees must be employed by the Group at the end of the performance period in order for the Share Rights to vest. The maximum
number of Share Rights that an employee was granted is a function of the employee’s Total Fixed Remuneration (TFR) and the 20 trading
days daily volume weighted average sale price of company shares sold on the ASX ending on the trading day prior to the start of the
performance period.
If the Company is subject to a Change of Control Event, all unvested Share Rights will immediately vest at 100%, with any performance
criteria being waived.
Participation
This share price-linked LTIP provided coverage for various levels of eligible employees from FY2021 which include:
a. One member of the Executive Management Team (EMT) received an LTIP percentage of 30% of their TFR until FY2019;
b. Eligible employees who are in roles which influence and drive the strategic direction of the Group’s business or who are senior
managers with responsibility for one or more defined functions, departments or outcomes were eligible to receive a maximum
LTIP percentage of 20% or 30% of TFR; and
Eligible employees who are in roles which are focused on the key drivers of the operational parts of the Group’s business
received a maximum LTIP percentage of 10% of TFR.
c.
All other eligible employees are integral to the success of the Group 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:
Share Rights can only be dealt with upon vesting at the end of the three-year service period; and
1.
2. No performance conditions apply.
In 2021, Central conducted an external review of the effectiveness of the LTIP in providing a relevant incentive to all levels of personnel.
The review took into account many factors, including the history of rewards under the scheme, taxation implications for employees, near
and longer-term drivers of shareholder value and alternative incentive scheme structures used by peers and the broader market. As a
result of the review:
i)
ii)
iii)
No further LTIPs have been granted under the existing LTIP structure described above from 1 July 2021;
The Managing Director (subject to shareholder approval) and EMT are eligible to participate in an Executive Incentive Plan (EIP)
from FY2022 (refer Section G of this report); and
Incentive for all other employees, including those in categories b and c above have been re-weighted to a single STIP
opportunity (refer Section H of this report) with eligibility to participate in the Central Petroleum $1,000 Exempt Plan.
Participation
The ESOP replaced the previous LTIP for participating executives and any Share Options granted under the ESOP replaced the LTIP Share
Rights that would otherwise have been granted in FY2020, FY2021 and FY2022 under the LTIP.
Key terms and vesting conditions
Each Share Option was issued for no consideration and entitled the participant to subscribe for one Share upon exercise of the Share
Option.
The amount payable upon exercise of each Share Option was $0.20 (Exercise Price). The Share Options were exercisable from 1 July 2022
until 30 June 2023.
Performance
No Share Options were exercised by 30 June 2023. All Share Options subsequently lapsed on 1 July 2023.
Participation
In 2021, Central established an EIP for key executives to align executive performance with the achievement of key objectives for FY2022
and the following two years.
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 (ERP) 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 period ending 30 June.
The Service Rights are the right to acquire fully paid ordinary shares for no exercise price at the end of the vesting period and can be
exercised up to five years from the grant date. To maintain alignment with shareholders, the Service Rights have a dividend and return of
capital entitlement whereby the Service Rights convert to one share plus an additional number of shares equal in value to the dividends
paid, or capital returned during the period from grant to exercise.
If a Change of Control Event (as defined in the ERP Rules) occurs, the Board has the discretion to determine the appropriate treatment
regarding any unvested or unexercised Share Rights
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 Sections J and K of this report.
FY2023 Performance
After assessment of the achievement of the Corporate KPIs (refer Section H of this report) and the Company’s performance during the
year, eligible executives were entitled to receive, on average, 45% of their maximum EIP bonus. Of this award, 33% was paid in September
2023, while the remaining 67% will be granted as Service Rights that vest over the next three years in equal tranches.
The STIP is a performance-based plan comprising a matrix of corporate and individual Key Performance Indicators (KPIs) for eligible
employees.
The Company’s Board sets the maximum award achievable in any year under the STIP (normally expressed as a percentage of total fixed
remuneration (TFR)), which is contingent on the achievement of the KPIs. The KPIs are set at the beginning of each year to incentivise staff
to achieve the goals in the next year that the Board consider are key to Central’s near-term performance and longer-term strategic
direction. Neither the Board nor the Company guarantee any payment from the STIP, nor do they guarantee any performance level of the
Company in future years.
Participation
The STIP operates with three levels of participation for eligible employees, each with a different level of maximum reward:
1
2
3
30 %
20 %
10 %
At the start of each performance period, the CEO nominates a level of participation for each eligible employee after considering factors
such as the eligible employee’s:
Involvement in strategic and operational aspects of management;
a) Role and responsibilities;
b)
c) Ability to be a key driver of the operational parts of the Group’s business; and
d) Ability to influence the Group’s performance.
From 1 July 2021, the CEO and executives who participate in the EIP are not eligible to participate in the STIP (refer Section G of this
report).
At the Board’s discretion the STIP award may be paid through a combination of cash and/or Company securities.
FY2023 Performance
After assessment of the achievement of the KPIs below and the Group’s performance during the year, eligible employees were entitled to
receive, on average, 51% of their maximum STIP bonus. The STIP bonuses are scheduled to be paid in September 2023.
The Financial Year 2023 STIP (FY2023 STIP) was designed to recognise and reward individual effort by connecting individual KPIs and
corporate KPIs and was assessed across three categories:
Corporate KPIs
Individual KPIs
60 %
40 %
100 %
27 %
24 % (avg)
45% satisfaction of corporate KPIs
60% satisfaction of individual KPIs
51 % (avg)
The majority of employees could earn a maximum of 10% of TFR, whilst more senior employees could earn either a maximum of 20% or
30% of TFR from the FY2023 STIP, depending on their participation level.
Corporate KPIs for FY2023:
Production (gas – sales volume)
Assessed against budget
Total Cost1
Total group operating and capital expenditure for agreed
scope of works assessed against budget
Recompletions/Development
Assessed against budget, commercial viability, schedule
and timing hurdles
Farmout
Assessed against the number of binding agreements
Funding
Assessed against the projected two year capital
requirements for existing commitments in FY2023
Traditional Owner cultural heritage
Assessed against compliance with agreements
Safety
Total Recordable Incident Frequency Rate (TRIFR)
Process Safety
Unplanned or uncontrolled release of materials from a
process (loss of primary containment – LOPC)
Environment Recordable environmental incidents
Alice Springs local and indigenous employment
17%
17%
17%
17%
17%
3%
3%
3%
3%
3%
1 Not rewarded for works that were essential but not completed, e.g. capital project delay or deferral. Excludes exploration and specific recompletions / development
activity which is assessed as a separate KPI.
Individual KPIs
Individual KPIs provide significant relevance to each role in each department, and for FY2023 were assessed as achieving an average of 60%
(or a weighted average of 24% out of a maximum possible 40%).
Participation
For a small number of selected KMP’s and other selected operational employees, a retention incentive was implemented as part of the
retention strategy made in connection with the portfolio Strategic Review announced in August 2022.
Key terms and vesting conditions
The retention incentive is a cash payment equal to 15% of the selected KMP’s and employees’ Total Fixed Remuneration (TFR). The
retention incentive is conditional upon the employee remaining employed by the Group in the period up to when the payment is made
after the earlier of completion of a transaction resulting from the Strategic Review and 30 June 2024.
Table 1 identifies the Actual Remuneration received by Senior Executives in respect of the 2023 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 (2023: 5.3 cents per share, 2022: 11.0 cents per share).
The table below has been provided to assist shareholders to understand the remuneration received in respect of each financial year ending
30 June. The table is a voluntary disclosure and as such has not been prepared in accordance with the disclosure requirements of the
Accounting Standards or Corporations Act 2001. See Table 2 for Executive KMP remuneration in accordance with these requirements.
Executive KMP
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart4
Jonathan Snape5
Daniel White
Total Executive KMP
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
654,572
625,750
535,557
511,860
353,926
338,050
113,160
409,450
194,107
330,001
475,523
454,410
2,326,845
2,669,521
117,823
156,438
64,267
85,310
42,471
56,342
—
68,242
—
55,000
57,063
75,735
281,624
497,067
8,192
7,470
8,192
7,470
8,192
7,470
2,007
7,470
4,895
6,984
8,192
7,470
55,833
—
30,447
—
20,108
—
4,043
—
9,815
—
50,994
46,505
836,420
789,658
638,463
604,640
424,697
401,862
119,210
485,162
208,817
391,985
591,772
584,120
39,670
44,334
171,240
46,505
2,819,379
3,257,427
1 Total Fixed Remuneration includes salaries, fees and superannuation contributions.
2
3 Shares comprise any shares to vest from the EIP or LTIP from prior years where the performance period ended 30 June 2023 and are valued at that date. Vesting will
Includes car parking and other fringe benefits.
occur upon the issue of a vesting notice.
4 Duncan Lockhart resigned 31 August 2022.
5
Jonathan Snape resigned 20 January 2023.
Non-Executive Directors
Stephen Gardiner
2023
2022
Troy Harry4
2023
2022
Katherine Hirschfeld 2023
2022
Agu Kantsler
2023
2022
70,833
62,500
66,402
—
78,000
78,000
62,500
62,500
Michael McCormack 2023
2022
117,500
117,500
Former Non-Executive Directors
Stuart Baker5
Sub-total
Executives
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart6
Jonathan Snape7
Daniel White
Sub-total
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
14,167
67,500
409,402
388,000
640,142
613,881
508,712
501,018
340,936
321,088
66,458
400,660
170,679
315,318
469,673
450,596
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
117,823
156,438
81,370
85,310
42,471
56,342
—
68,242
—
55,000
57,063
75,735
8,192
7,470
8,192
7,470
8,192
7,470
2,007
7,470
4,895
6,984
8,192
7,470
2,196,600
2,602,561
298,727
497,067
39,670
44,334
Total Remuneration 2023
2022
2,606,002
2,990,561
298,727
497,067
39,670
44,334
7,438
6,250
6,972
—
8,190
7,800
6,563
6,250
12,338
11,750
1,488
6,750
42,989
38,800
25,292
23,568
25,292
23,568
25,292
23,568
6,323
23,568
14,543
23,568
25,292
23,568
122,034
141,408
165,023
180,208
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
18,251
18,603
—
—
7,300
7,441
18,251
18,603
33,895
34,548
—
18,603
77,697
97,798
22,307
13,639
9,717
7,119
5,856
4,470
(15,824)
5,506
(2,706)
2,706
18,425
10,367
177,683
277,153
117,477
241,598
76,803
158,595
(43,061)
192,505
(21,944)
39,722
135,958
151,392
37,775
43,807
442,916
1,060,965
37,775
43,807
520,613
1,158,763
96,522
87,353
73,374
—
93,490
93,241
87,314
87,353
163,733
163,798
15,655
92,853
530,088
524,598
991,439
1,092,149
750,760
866,083
499,550
571,533
15,903
697,951
165,467
443,298
714,603
719,128
3,137,722
4,390,142
3,667,810
4,914,740
—
—
—
—
—
—
—
—
—
—
—
—
—
—
30%
40%
26%
38%
24%
38%
—
37%
—
21%
27%
32%
24%
35%
22%
32%
Includes movements in annual leave provisions.
1
2 Short term incentives are unpaid at the end of the financial year.
3 The fair values of share rights granted under the LTIP 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. Rights granted under the EIP at valued at market value on the grant date. The values are allocated to each reporting period evenly over the
period from service commencement 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. Non-executive directors had the
discretion to sacrifice up to 25% of their Base Fees to earn share rights which automatically vested on 30 June.
4 Troy Harry was appointed 1 September 2022.
5 Stuart Baker resigned 30 August 2022.
6 Duncan Lockhart resigned 31 August 2022.
7
Jonathan Snape resigned 20 January 2023.
Leon Devaney
Ross Evans1
Damian Galvin
Duncan Lockhart
Jonathan Snape
Daniel White
Total
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
261,829
250,300
142,815
136,496
94,380
90,147
N/A
109,187
N/A
88,000
126,806
121,176
625,830
795,306
117,823
156,438
64,267
85,310
42,471
56,342
N/A
68,242
N/A
55,000
57,063
75,735
281,624
497,067
45.0%
62.5%
45.0%
62.5%
45.0%
62.5%
N/A
62.5%
N/A
62.5%
45.0%
62.5%
45.0%
62.5%
55.0%
37.5%
55.0%
37.5%
55.0%
37.5%
N/A
37.5%
N/A
37.5%
55.0%
37.5%
55.0%
37.5%
1 In addition to this short term incentive, Ross Evans is also entitled to a retention incentive of 15% of total fixed remuneration implemented as part of the retention
strategy made in connection with the Portfolio Strategic Review announced in August 2022. The incentive is conditional upon Mr Evans remaining employed by the
Company and is payable as soon as practicable after the earlier of completion of a transaction resulting from the Strategic Review and 30 June 2024. An amount of
$17,103 relating to this retention incentive was accrued for the service period to 30 June 2023.
Non-Executive Directors1
Stuart Baker2
Stephen Gardiner
Katherine Hirschfeld
Agu Kantsler
Michael McCormack
Sub-total
Executives3
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart4
Jonathan Snape5
Daniel White
Sub-total
Total
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
—
23 Nov 21
11 Nov 22
23 Nov 21
11 Nov 22
23 Nov 21
11 Nov 22
23 Nov 21
11 Nov 22
23 Nov 21
10 Nov 22
—
19 Sep 22
—
19 Sep 22
—
19 Sep 22
—
19 Sep 22
—
19 Sep 22
—
—
161,765
217,275
161,765
86,910
64,706
217,275
161,765
403,511
300,420
924,971
850,421
3,160,353
—
1,723,434
—
1,138,215
—
76,283
—
1,111,113
—
1,530,000
—
8,739,398
—
9,664,369
850,421
—
0.115
0.084
0.115
0.084
0.115
0.084
0.115
0.084
0.115
0.083
—
0.096
—
0.096
—
0.096
—
0.096
—
0.096
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
30 Jun 26
30 Jun 27
30 Jun 26
30 Jun 27
30 Jun 26
30 Jun 27
30 Jun 26
30 Jun 27
30 Jun 26
10 Nov 27
—
19 Sep 27
—
19 Sep 27
—
19 Sep 27
—
19 Sep 27
—
19 Sep 27
—
1 Represents a portion of Directors Fees sacrificed. These Share Rights vested on 30 June – Refer Section M of this report.
2 Stuart Baker resigned 30 August 2022.
3 Represent Rights awarded under the Executive Incentive Plan which vest over three years on 30 June of the current and two subsequent financial years.
4 Duncan Lockhart resigned 31 August 2022.
5 Jonathan Snape resigned 20 January 2023. 740,742 of these Share Rights were subsequently cancelled and a further 185,185 did not vest.
The following factors and assumptions were used in determining the fair value of rights granted to key management personnel during
FY2023:
19 Sep 20221
10 Nov 20221
11 Nov 20222
19 Sep 2027
10 Nov 2027
30 Jun 2027
$0.096
$0.083
$0.084
Nil
Nil
Nil
$0.096
$0.083
$0.084
N/A
N/A
N/A
N/A
N/A
N/A
—
—
—
1 EIP Rights for the plan year commencing 1 July 2021.
2 Share Rights granted to Non-Executive Directors. The fair value reflects the value of Director Fees sacrificed – Refer Section M of this report.
The following factors and assumptions were used in determining the fair value of rights granted to key management personnel during
FY2022:
23 Nov 20211
30 Jun 2026
$0.115
Nil
$0.115
N/A
N/A
—
1 Share Rights granted to Non-Executive Directors. The fair value reflects the value of Director Fees sacrificed – Refer Section M of this report.
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart3
Jonathan Snape4
Daniel White
Total
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2023
2022
2023
2022
1,053,451
—
574,478
—
379,405
—
76,283
—
185,186
—
510,000
1,510,476
983,204
4,289,279
983,204
01 Jul 21
—
01 Jul 21
—
01 Jul 21
—
01 Jul 21
—
01 Jul 21
—
01 Jul 21
—
—
—
—
—
—
—
—
—
—
—
—
—
01 Jul 20
01 Jul 19
1,053,451
—
574,478
—
379,405
—
76,283
—
185,186
—
510,000
452,160
422,777
3,230,963
422,777
100%
—
100%
—
100%
—
100%
—
100%
—
100%
30%
43%
75%
43%
Nil
—
Nil
—
Nil
—
Nil
—
Nil
—
Nil
70%
57%
25%
57%
1 The number of Rights that vested in respect of plan years commencing 1 July 2019 and 1 July 2020 relates to Share Rights granted in prior financial years under the
Long Term Incentive Plan. Prior to forfeiture and at the discretion of the Board, LTIP Rights for the plan year commencing 1 July 2020 may be subjected to retest
against the performance hurdles at 31 December 2023.
2 The proportion of Rights vested represents the proportion of the maximum number of Rights that were eligible for vesting during the financial year.
3 Duncan Lockhart resigned 31 August 2022.
4 Jonathan Snape resigned 20 January 2023.
In addition, 924,971 Share Rights vested on 30 June 2023 (2022: 850,421), representing 100% of Share Rights granted during the year to
Non-Executive Directors in return for the sacrifice of Directors’ fees – refer Table 4 above.
Key Management Personnel may receive Service Rights to shares of the Company under the Executive Incentive Plan (refer Section G of
this report).
Key Management Personnel have, in previous years, participated in the Group’s Long Term Incentive Plans under which they may have
received:
a) Rights to shares of the Company under the LTIP 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).
Non-Executive Directors were entitled to sacrifice up to 25% of their Base Fee to earn Share Rights which vested on 30 June.
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:
Non-executive Directors
Stuart Baker1
Stephen Gardiner
Katherine Hirschfeld
Agu Kantsler
Michael McCormack
Sub-total
Executives
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart2
Jonathan Snape3
Daniel White
Sub-total
Total
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
161,765
—
161,765
N/A
64,706
—
161,765
—
300,420
—
850,421
—
1,074,860
2,333,280
405,655
1,184,509
243,198
243,198
304,213
304,213
—
N/A
2,820,949
3,625,933
4,848,875
7,691,133
5,699,296
7,691,133
—
161,765
217,275
161,765
86,910
64,706
217,275
161,765
403,511
300,420
924,971
850,421
—
—
—
—
—
—
—
—
—
—
—
—
3,160,353
—
1,723,434
—
1,138,215
—
76,283
—
1,111,113
—
1,530,000
—
—
(1,258,420)
—
(533,515)
—
—
(84,504)
—
(740,742)
—
(560,427)
(551,415)
8,739,398
—
(1,385,673)
(2,343,350)
9,664,369
850,421
(1,385,673)
(2,343,350)
—
—
—
—
(64,706)
—
(161,765)
—
(300,420)
—
(526,891)
—
—
—
—
(245,339)
—
—
—
—
—
—
(422,777)
(253,569)
(422,777)
(498,908)
(949,668)
(498,908)
(161,765)
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
161,765
379,040
161,765
86,910
64,706
217,275
161,765
403,511
300,420
(161,765)
N/A
1,086,736
850,421
N/A
N/A
N/A
N/A
N/A
N/A
(295,992)
N/A
(370,371)
N/A
N/A
N/A
(666,363)
—
1,632,140
578,689
574,478
—
379,405
—
N/A
—
N/A
—
510,000
—
3,096,023
578,689
N/A
—
—
—
—
—
—
—
—
—
—
—
2,603,073
496,171
1,554,611
405,655
1,002,008
243,198
N/A
304,213
N/A
—
2,857,745
2,820,949
8,017,437
4,270,186
(828,128)
N/A
4,182,759
1,429,110
8,017,437
4,270,186
1 Stuart Baker resigned 30 August 2022
2 Duncan Lockhart resigned 31 August 2022
3 Jonathan Snape resigned 20 January 2023. Of the 370,371 rights held on departure, 185,185 subsequently lapsed.
Key Management Personnel
TBD1
Leon Devaney
10 Nov 2022
10 Nov 2022
10 Nov 2022
11 Nov 2020
TBD1
19 Sep 2022
19 Sep 2022
19 Sep 2022
11 Nov 2020
TBD1
19 Sep 2022
19 Sep 2022
19 Sep 2022
11 Nov 2020
TBD1
19 Sep 2022
19 Sep 2022
19 Sep 2022
11 Nov 2020
24 Jul 2020
Ross Evans
Damian Galvin
Daniel White
Total
Deferred Share Rights – FY2023 EIP1
Deferred Share Rights – FY2022 EIP
Deferred Share Rights – FY2022 EIP
Deferred Share rights – FY2022 EIP
Deferred Share Rights – STIP3
Deferred Share Rights – FY2023 EIP1
Deferred Share Rights – FY2022 EIP
Deferred Share Rights – FY2022 EIP
Deferred Share Rights – FY2022 EIP
Deferred Share Rights – STIP3
Deferred Share Rights – FY2023 EIP1
Deferred Share Rights – FY2022 EIP
Deferred Share Rights – FY2022 EIP
Deferred Share Rights – FY2022 EIP
Deferred Share Rights – STIP3
Deferred Share Rights – FY2022 EIP1
Deferred Share Rights – FY2022 EIP
Deferred Share Rights – FY2022 EIP
Deferred Share Rights – FY2022 EIP
Deferred Share Rights – STIP4
Deferred Share Rights – LTIP
—
1,053,451
1,053,451
1,053,451
496,171
—
574,478
574,478
574,478
405,655
—
379,405
379,405
379,405
243,198
—
510,000
510,000
510,000
327,269
1,510,476
10,534,771
—
30 Jun 2025
30 Jun 2024
30 Jun 2023
01 Jul 2023
—
30 Jun 2025
30 Jun 2024
30 Jun 2023
01 Jul 2023
—
30 Jun 2025
30 Jun 2024
30 Jun 2023
01 Jul 2023
—
30 Jun 2025
30 Jun 2024
30 Jun 2023
01 Jul 2023
30 Jun 2023
150,552
43,718
29,146
—
—
82,119
27,575
18,383
—
—
54,268
18,211
12,141
—
—
72,914
24,480
16,320
—
—
—
549,827
1 Share rights as part of the FY2023 EIP are expected to be granted during FY2024. The number of rights to be granted is determined based on Central
Petroleum’s share price for the 20 days after release of the June 2023 quarterly report, which is calculated as 5.86 cents per right.
2 Vesting Period End Date is the end of the service period at which an entitlement to vesting is determined. The actual vesting date may be a later date.
3 The maximum value of the share rights yet to vest has been determined as the amount of the grant date fair value of the rights that is yet to be expensed.
For the FY2023 EIP, the maximum value yet to vest is based on the proportion (two-thirds) of the total incentive that will convert to share rights. The
minimum value to vest is nil, as the rights will be forfeited if the vesting conditions are not met.
4 The FY2020 STIP was awarded as rights to deferred shares instead of cash. These rights vested subsequent to the end of the financial year, on 1 July 2023.
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:
Key Management Personnel
Leon Devaney
2023
2022
Ross Evans
Damian Galvin
Duncan Lockhart1
Total
2023
2022
2023
2022
2023
2022
2023
2022
5,105,000
5,105,000
4,170,025
4,170,025
2,750,000
2,750,000
3,333,333
3,333,333
15,358,358
15,358,358
—
—
—
—
—
—
—
—
—
—
$0.20 01 Jul 2023
$0.20 01 Jul 2023
$0.20 01 Jul 2023
$0.20 01 Jul 2023
$0.20 01 Jul 2023
$0.20 01 Jul 2023
$0.20 01 Jul 2023
$0.20 01 Jul 2023
$0.20 01 Jul 2023
$0.20 01 Jul 2023
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
N/A
N/A
N/A
N/A
N/A
N/A
(3,333,333)
N/A
5,105,000
5,105,000
4,170,025
4,170,025
2,750,000
2,750,000
N/A
3,333,333
(3,333,333)
N/A
12,025,025
15,358,358
1 Duncan Lockhart resigned 31 August 2022.
2 No options were exercised, and all options were subsequently cancelled on 1 July 2023.
Non-Executive Directors
Stuart Baker1
Troy Harry2
Stephen Gardiner
Katherine Hirschfeld
Agu Kantsler
Michael McCormack
Sub-total
Other Key Management Personnel
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart3
Jonathan Snape4
Daniel White
Sub-total
Total KMP
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
1 Stuart Baker resigned 30 August 2022.
2 Troy Harry was appointed 1 September 2022.
3 Duncan Lockhart resigned 31 August 2022.
4 Jonathan Snape resigned 20 January 2023.
—
—
N/A
N/A
—
N/A
760,850
760,850
—
—
—
—
N/A
N/A
53,340,268
N/A
N/A
—
N/A
N/A
N/A
N/A
N/A
N/A
760,850
760,850
53,340,268
—
2,606,757
2,606,757
386,184
140,845
141,000
141,000
—
—
—
N/A
2,562,643
2,309,074
5,696,584
5,197,676
6,457,434
5,958,526
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
—
N/A
N/A
—
—
53,340,268
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
64,706
—
161,765
—
300,420
—
526,891
—
—
—
—
245,339
—
—
—
—
—
—
422,777
253,569
422,777
498,908
949,668
498,908
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
—
N/A
—
N/A
N/A
N/A
—
—
—
—
N/A
—
53,340,268
N/A
—
—
825,556
760,850
161,765
—
300,420
—
54,628,009
760,850
2,606,757
2,606,757
386,184
386,184
141,000
141,000
N/A
—
N/A
—
2,985,420
2,562,643
6,119,361
5,696,584
60,747,370
6,457,434
The details of service agreements of the key management personnel of the Consolidated Entity as of 1 July 2023 are as follows:
Leon Devaney
Managing Director & Chief Executive Officer
Full time permanent
Ross Evans
Chief Operations Officer
Damian Galvin
Chief Financial Officer
Full time permanent
Full time permanent
Daniel White
Group General Counsel & Company Secretary
Full time permanent
$681,849
$558,079
$369,179
$495,639
6-months
6-months
6-months
3-months
1 Total Annual Fixed Remuneration, effective 1 July 2023 includes compulsory superannuation contributions.
2
In certain exceptional circumstances (such as breach or gross misconduct) a shorter notice period applies.
If the employment of a member of key management personnel listed above is terminated within 12-months of a change of control event,
the executive is entitled to a termination payment equivalent to 12-months TFR (reduced by any redundancy entitlement received).
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 FY2023. Directors had the discretion to sacrifice up to 25% of their Base
Fee to earn Share Rights. The issue of Share Rights to Directors was approved under ASX Listing Rule 10.14 at the Company’s Annual
General Meeting held on 10 November 2022.
Chair
Non-Executive Director
$130,000
$70,000
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. There are no loans issued to key
management personnel and no related party transactions with directors during the year.
Signed in accordance with a resolution of the directors:
Michael McCormack
Chair
19 September 2023
Auditor’s Independence Declaration
As lead auditor for the audit of Central Petroleum Limited for the year ended 30 June 2023, 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
19 September 2023
PricewaterhouseCoopers, ABN 52 780 433 757
480 Queen Street, BRISBANE QLD 4000, GPO Box 150, BRISBANE QLD 4001
T: +61 7 3257 5000, F: +61 7 3257 5999
Liability limited by a scheme approved under Professional Standards Legislation
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 25. These pages are not part of these financial statements.
The financial statements were authorised for issue by the Directors on 19 September 2023. 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.
2
4(a)
3
4(e)
4(b)
4(c)
5
Revenue from contracts with customers – sale of hydrocarbons
Cost of sales
Gross profit
Other income
Exploration expenditure
General and administrative expenses net of recoveries
Finance costs
(Loss)/Profit before income tax
Income tax expense
(Loss)/Profit for the year
Other comprehensive profit/(loss) for the year, net of tax
Total comprehensive (loss)/profit for the year
Total comprehensive (loss)/profit attributable to members of the parent entity
Earnings per share for profit or loss attributable to the ordinary equity
holders of the company:
39,255
(26,408)
12,847
1,880
(13,093)
(4,797)
(4,797)
(7,960)
—
(7,960)
—
(7,960)
(7,960)
42,151
(27,351)
14,800
37,300
(21,647)
(4,846)
(4,287)
21,320
—
21,320
—
21,320
21,320
Basic (loss)/earnings per share (cents)
Diluted (loss)/ earnings per share (cents)
22(a)
22(b)
(1.09)
(1.09)
2.94
2.88
* Refer Note 1 regarding the restatement of FY2022 comparatives as a result of changing the presentation of certain expenses from by nature to by function.
The accompanying notes form part of these financial statements.
ASSETS
Current assets
Cash and cash equivalents
Trade and other receivables
Inventories
Total current assets
Non-current assets
Property, plant and equipment
Right of use assets
Exploration assets
Other intangible assets
Other financial assets
Goodwill
Total non-current assets
Total assets
LIABILITIES
Current liabilities
Trade and other payables
Deferred revenue
Borrowings
Lease liabilities
Provisions
Total current liabilities
Non-current liabilities
Deferred revenue
Borrowings
Lease liabilities
Provisions
Total non-current liabilities
Total liabilities
Net assets
EQUITY
Contributed equity
Reserves
Accumulated losses
Total equity
7
8
9
10
11
12
13
14
15
16
2(b)
17(a)
11
18
2(b)
17(b)
11
18
19 (a)
20
21
13,826
6,675
3,550
24,051
60,192
551
7,999
332
3,053
1,953
74,080
98,131
3,009
3,536
4,376
426
5,597
16,944
11,632
23,150
201
26,816
61,799
78,743
19,388
21,647
26,872
3,868
52,387
53,846
922
8,397
379
4,410
1,953
69,907
122,294
13,526
5,309
4,500
413
6,325
30,073
13,614
26,309
588
25,180
65,691
95,764
26,530
197,776
31,433
(209,821)
19,388
197,776
30,615
(201,861)
26,530
The accompanying notes form part of these financial statements.
Balance at 1 July 2021
197,776
29,094
(223,181)
Total profit for the year
Other comprehensive loss
Total comprehensive profit for the year
Transactions with owners in their capacity
as owners
Share based payments
Share issue costs
—
—
—
—
—
—
—
—
—
1,524
(3)
1,521
21,320
—
21,320
—
—
—
Balance at 30 June 2022
197,776
30,615
(201,861)
Total loss 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
—
—
—
—
—
—
—
—
—
820
(2)
818
(7,960)
—
(7,960)
—
—
—
3,689
21,320
—
21,320
1,524
(3)
1,521
26,530
(7,960)
—
(7,960)
820
(2)
818
Balance at 30 June 2023
197,776
31,433
(209,821)
19,388
The accompanying notes form part of these financial statements.
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 (outflow)/inflow from operating activities
Cash flows from investing activities
Payments for property, plant and equipment
Proceeds from sale of producing assets and property, plant and equipment
Redemption/(lodgement) of security deposits and bonds
Net cash (outflow)inflow from investing activities
Cash flows from financing activities
Payments for the issue of securities
Proceeds from borrowings
Repayment of borrowings
Transaction costs related to borrowings
Principal elements of lease payments
Net cash outflow from financing activities
Net decrease in cash and cash equivalents
Cash and cash equivalents at the beginning of the financial year
27
3(b)
28(b)
28(b)
28(b)
38,050
519
248
—
(2,853)
(9,629)
(28,391)
(2,056)
(2,857)
3
1,356
(1,498)
(2)
1,000
(4,625)
(195)
(445)
(4,267)
(7,821)
21,647
44,333
59
42
11
(2,472)
(10,121)
(28,212)
3,640
(10,791)
28,305
(108)
17,406
(3)
—
(36,000)
—
(561)
(36,564)
(15,518)
37,165
Cash and cash equivalents at the end of the financial year
7
13,826
21,647
The accompanying notes form part of these financial statements.
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”).
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.
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.
The presentation of the Consolidated Statement of Comprehensive Income has been restated in the current year to reclassify certain
expenses by function rather than by nature to align with industry peers. Employee benefits and associated costs related to cost of sales or
exploration activities had previously been allocated to these items. Share based payments and other employee benefits and associated
costs, net of recoveries from joint venturers, have now been reclassified to general & administrative expenses. Depreciation and
amortisation expenses have been re-allocated between cost of sales and general and administrative expenses (also reflected in Note 4
Expenses, Note 23 Segment Reporting, and Note 26 Deed of Cross Guarantee). To ensure comparability, amounts disclosed for the
comparative period have been reclassified. The impacts of the reclassification for the Group for FY2022 are as follows:
2022 Expenses as reported
Cost of sales
General and administrative costs
Employee benefits and associated costs net of recoveries
Share based payments
Depreciation and amortisation
Total 2022 comparatives as reported in FY2023
2022
As reported
$’000
(21,257)
(1,043)
(1,594)
(1,524)
(6,779)
Reclassified 2022 expenses by function
Allocated to
Cost of Sales
$’000
(21,257)
—
—
—
(6,094)
(27,351)
Allocated to General &
Administrative
$’000
—
(1,043)
(1,594)
(1,524)
(685)
(4,846)
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 Board has considered multiple cash flow forecast scenarios prepared by management for the next twelve months and believe the
Group has sufficient cash flows under these scenarios to continue operations as planned.
The Group’s ability to complete its planned three well sub-salt exploration program in its current form is dependent on farm-out
arrangements under which the Group was to be carried for its share of the costs for two of the three planned wells (up to $10.6 million).
The Directors have formed the view that Peak Helium will not be able to fund their obligations under the various farm-out arrangements
and the relevant joint venturers are considering the future structure and timing of the exploration program. In the expectation that the
farm-out funding is not forthcoming, the Group has alternative options available for the permits and wells. In assessing alternative
arrangements, the Board has considered options such as deferral of permit commitments, new farm-outs or, alternatively, relinquishment
of exploration permits. If permits are relinquished, the carrying value of relevant Exploration Assets could be impacted. The Board and
management are confident alternative arrangements will be made and will not affect the Group’s ability to continue as a going concern.
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.
The Group has not applied any pronouncements to the annual reporting period beginning on 1 July 2022 where such application would
result in them being applied prior to them becoming mandatory.
These financial statements have been prepared under the historical cost convention.
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:
The Group recognises any obligations for removal and restoration that are incurred during a particular period as a consequence of having
undertaken exploration and development 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 18.
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 K of the Remuneration Report.
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 expected cost
of production, regulatory changes and expected future commodity prices. Ongoing exploration and evaluation expenditure is expensed as
incurred. Acquisition expenditure is capitalised if activities in the area of interest have not yet reached a stage that permits a reasonable
assessment of the existence or otherwise of economically recoverable reserves. To the extent that the capitalised acquisition expenditure
is determined not to be recoverable in future, profits and net assets will be reduced in the period in which this determination is made.
Further information on the carrying value of capitalised exploration and evaluation expenditure can be found in Note 12.
Property, plant and equipment and other non-financial assets are written down immediately to their recoverable amount if the asset’s
carrying amount is greater than its estimated recoverable amount. Goodwill is tested for impairment annually or whenever events or
changes in circumstances indicate that the carrying amount may not be recoverable. For the purposes of assessing impairment, assets are
grouped at the lowest levels for which there are separately identifiable cash inflows which are largely independent of the cash inflows from
other assets or groups of assets (cash-generating units). Where discounted cash flows are used to assess recoverability of non-financial
assets, the Group is required to use assumptions in respect of future commodity prices, foreign exchange rates, interest rates and
operating costs, along with the possible impact of climate-related and other emerging business risks in determining expected future cash
flows from operations. Further information on the nature and carrying value of other non-financial assets can be found in Notes 10, 11, 13
and 15. Testing for impairment of goodwill and other non-financial assets in FY2023 was assessed against estimated future cash flows from
available 2P reserves over a 20-year period (refer Note 15).
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 Comprehensive Income.
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 Consolidated Statement of
Comprehensive Income, statement of changes in equity and balance sheet respectively.
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 33.
Operating segments are reported in Note 23 in a manner consistent with the internal reporting provided to the chief operating decision
makers. The chief operating decision makers, who are responsible for allocating resources and assessing performance of the operating
segments, have been identified as the Executive Management Team.
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.
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.
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.
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 the point of load-out from third party storage facilities
(liquids).
Take or pay proceeds received are taken to revenue at the earlier of physical delivery of the product to the customer, upon forfeiture of
the right to take product under the contract, or when it is considered that the customer will not be able to take physical delivery of the
product during the remaining term of the contract.
Amounts received under pre-sale agreements are initially recognised as Deferred Revenue when no cash settlement option exists for the
customer. Revenue is recognised as the product is physically supplied.
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.
A contract liability (deferred revenue) is recorded for obligations under sales contracts to deliver natural gas in future periods for which
payment has already been received (including “take-or-pay” arrangements). The Group applies the practical expedient in paragraph 121 of
AASB 15 and does not disclose information on the transaction price allocated to performance obligations that are unsatisfied.
Interest income is recognised on a time proportionate basis that takes into account the effective yield on the financial assets.
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.
Central Petroleum Limited and its wholly owned Australian controlled entities have implemented the tax consolidation legislation. The
head entity is Central Petroleum Limited. As a consequence, these entities are taxed as a single entity. The Company and the other entities
in the tax-consolidated group have entered into a tax funding and a tax sharing agreement.
The Group accounts for income taxes in accordance with UIG 1052 adopting the “Separate Taxpayer within Group Approach”.
The income tax expense or revenue for the period is the tax payable on the current period’s taxable income based on the applicable
income tax rate adjusted by changes in deferred tax assets and liabilities attributable to temporary differences. The current income tax
charge is calculated on the basis of the tax laws enacted or substantially enacted at the end of the reporting period in the countries where
entities in the Group generate taxable income.
Each individual entity recognises deferred tax assets and deferred tax liabilities arising from temporary differences on the basis that the
entity is subject to tax as part of the tax-consolidated group. Deferred tax assets are recognised for deductible temporary differences and
unused tax losses only if it is probable that future taxable amounts will be available to utilise those temporary differences and losses. Each
entity assesses the recovery of its unused tax losses and tax credits only in the period in which they arise and before assumption by the
head entity, applied in the context of the Group whether as a reduction of current tax of other entities in the group or as a deferred tax
asset of the head entity. The aggregate amount of losses or credits utilised or recognised as a deferred tax asset by the head entity is
apportioned on a systematic and reasonable basis.
Deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill. Deferred tax is also not accounted for if it
arises from initial recognition of an asset or liability in a transaction other than a business combination that, at the time of the transaction,
affects neither accounting nor taxable profit or loss. Deferred income tax is determined using tax rates (and laws) that have been enacted
or substantially enacted by the end of the reporting period and are expected to apply when the related deferred income tax asset is
realised, or the deferred income tax liability is settled.
Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets and liabilities and when the
deferred tax balances relate to the same taxation authority. Current tax assets and tax liabilities are offset where the entity has a legally
enforceable right to offset and intends either to settle on a net basis, or to realise the asset and settle the liability simultaneously.
The Group’s accounting policy for leases where the Group is lessee is described in Note 11.
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.
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.
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 32.
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.
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 14).
At initial recognition, the Group measures a financial asset at its fair value plus, in the case of a financial asset not at fair value through
profit or loss, transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets
carried at fair value through profit or loss are expensed in profit or loss. Financial assets carried at fair value through profit or loss are
revalued to fair value at the end of the reporting period. Loans and receivables are subsequently carried at amortised cost using the
effective interest method.
The Group considers an allowance for expected credit losses (ECLs) for its financial assets. The Group applies a simplified approach in
calculating ECLs which is based on an assessment on its historical credit loss experience, adjusted for factors specific to the counterparty
and the economic environment.
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.
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.
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:
Buildings
Leasehold Improvements
Plant and Equipment
Motor Vehicles
10 – 40 years
4 – 10 years
2 – 30 years
4 – 12 years
Exploration and evaluation costs are expensed as incurred. Acquisition costs of rights to explore are capitalised in respect of each separate
area of interest and carried forward where: right of tenure of the area of interest is current; these costs are expected to be recouped
through sale or successful development and exploitation of the area of interest; or where exploration and evaluation activities in the area
of interest have not yet reached a stage that permits reasonable assessment of the existence of economically recoverable reserves. No
amortisation is charged on acquisition costs capitalised under this policy.
When an area of interest is abandoned or the Directors decide that it is not commercial, any accumulated costs in respect of that area are
written off in the financial period the decision is made. Each area of interest is also reviewed at the end of each accounting period and
accumulated costs written off to the extent that they will not be recoverable in the future.
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 23).
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.
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.
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.
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.
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.
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.
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.
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 termination 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.
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.
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.
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.
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.
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.
The financial information for the Parent Entity, Central Petroleum Limited, disclosed in Note 24, 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.
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.
The Group has applied the following standards and amendments for the first time for their annual reporting period commencing 1 July
2022:
•
AASB 2020-3 Amendments to Australian Accounting Standards – Annual Improvements 2018–2020 and Other Amendments [AASB 1,
AASB 3, AASB 9, AASB 116, AASB 137 & AASB 141].
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.
Sale of hydrocarbon products - point in time
Natural gas
Crude oil and condensate
Revenue released from Deferred Revenue in respect of ‘take or pay’ contracts1
Total revenue from contracts with customers
34,731
3,488
1,036
39,255
36,255
5,896
—
42,151
1 Represents amounts paid for gas under take or pay contracts for which the customer will no longer be able to take physical delivery of the
gas due to time and maximum daily quantity limits under the contract.
Revenue relating to contracts with major customers is disclosed in Note 23(f) – Segment Reporting.
Deferred Revenue – take-or-pay contracts1
Deferred Revenue – other gas sales contracts1
1,371
2,165
11,632
13,003
—
2,165
1,357
3,952
11,857
13,214
1,757
5,709
Total contract liabilities
1 Refer Note 1(e) (i) and (iii).
3,536
11,632
15,168
5,309
13,614
18,923
Carrying amount at 1 July 2022
Revenue recognised from the delivery of gas
Revenue released from take or pay contracts
Gas paid for but not taken during the period
Finance charges
Carrying amount at 30 June 2023
13,214
–
(1,036)
825
–
13,003
5,709
(4,114)
–
–
570
2,165
18,923
(4,114)
(1,036)
825
570
15,168
Interest
Income from financial assets at amortised cost
Income from the farmout of exploration interests (a)
Profit on disposal of 50% of interests in Amadeus Basin producing properties (b)
Profit on disposal of inventory and other assets
Total other income
533
304
795
—
248
1,880
63
665
—
36,559
13
37,300
On 31 March 2023 the Group completed the farmout of interests in certain explora(cid:415)on permits to Peak Helium (Amadeus Basin) Pty Ltd. In
accordance with the Farmout Agreement, the Group was en(cid:415)tled to receive reimbursement of expenditure previously incurred and
expensed by the Group from the effec(cid:415)ve date of the farmout transac(cid:415)on (1 October 2021). A total of $795,000 has been recorded as
Other Income in the current financial year rela(cid:415)ng to the farmout of explora(cid:415)on interests. This amount reflects reimbursement amounts
rela(cid:415)ng to prior financial year explora(cid:415)on expenditure and reduc(cid:415)ons in rehabilita(cid:415)on obliga(cid:415)ons previously expensed.
On 1 October 2021, the Group completed the sale of 50% of the Group’s interests in its Amadeus Basin producing assets to New Zealand
Oil and Gas Limited and Cue Energy Resources Limited. The Group recognised an accounting profit after tax of $36,559,000 in FY 2022
comprised as follows:
Cash consideration received, net of adjustments from effective date to completion date and net of cash
included in disposal
Transaction costs
Net cash received
Fair Value of deferred consideration receivable post completion
Total consideration net of transaction costs
Carrying value of non-cash assets disposed
Carrying value of liabilities directly associated with assets disposed and included in the disposal
Profit on disposal (after tax)
29,561
(1,256)
28,305
29,849
58,154
(62,512)
40,917
36,559
Refer Note 1(a) regarding the restatement of FY2022 comparatives as a result of changing presentation of expenses from by nature to by
function.
Depreciation and amortisation
Employee and contractor costs
Gas purchases
Other production costs
Royalties
Transportation and storage
Total cost of sales
Depreciation and amortisation
Employee and contractor costs
Share based payments
Other costs
Total general and administrative expenses
Interest and fees on debt facilities
Interest on lease liabilities
Amortisation of deferred finance costs
Accretion charges
Total finance costs
4(d)
4(f)
4(d)
11(b)
6,295
5,326
4,416
5,073
2,938
2,360
6,094
6,045
4,041
4,969
3,088
3,114
26,408
27,351
571
1,650
820
1,756
4,797
2,998
49
342
1,408
4,797
685
1,232
1,524
1,405
4,846
2,394
78
—
1,815
4,287
Depreciation
Buildings
Producing assets
Plant and equipment
Leasehold improvements
Right of use assets
Total depreciation
Amortisation
Other intangible assets - software
10
10
10
10
11(b)
175
3,371
2,752
10
442
6,750
176
3,384
2,582
16
521
6,679
13
116
100
Impairment expenses of $3,486,000 (FY2022: Nil) are included in exploration expenditure and relate to the following:
The Group intends to relinquish its interest in RL3 and RL4 and, as a result, has recognised the impairment of exploration assets during the
year amounting to $398,000 (Note 12).
There is a risk that Peak Helium (Amadeus Basin) Pty Ltd (“Peak”) may not be able to fund obligations under its various farmin
arrangements. As a result, the Group has recorded an impairment expense of $3,088,000 in respect of amounts due by Peak for
reimbursement of past costs.
No subsidies were received in the current financial year. During the previous financial year $11,000 was received from the Northern
Territory Government as training incentives for operational staff and recognised against net employee costs.
There were no rental expenses relating to operating leases that are not on the Balance Sheet during the current or prior financial year
(Note 11(b)).
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.
Current tax
Deferred tax
Income tax expense
(Loss)/profit before income tax expense
Prima facie tax benefit/(expense) at 30% (2022: 30%)
Tax effect of amounts which are not deductible in calculating taxable income:
Non-deductible expenses
Share based payments
Other items
Sub-total
Previously unrecognised deferred tax assets
Deferred tax assets not recognised
Income tax expense
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
—
—
—
(7,960)
2,388
(8)
(246)
—
2,134
—
(2,134)
—
1
(1)
—
—
—
—
21,320
(6,396)
(4)
(457)
(16)
(6,873)
6,873
—
—
1
(1)
—
Unutilised tax losses for which no deferred tax asset has been recognised
Potential tax benefit at 30%
142,134
42,640
139,120
41,736
Unutilised tax losses are available for use in Australia and are available to offset future taxable profits of the income tax consolidated
group, subject to the relevant tax loss recoupment requirements being met.
Deferred tax assets
Provisions and accruals
Receivables
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
Charged to the income statement
Closing balance at 30 June
Deferred tax assets to be recovered after more than 12-months
Deferred tax assets to be recovered within 12-months
Deferred tax liabilities
Capitalised exploration
Property, plant and equipment
Other items
Total deferred tax liabilities before set-offs
Set-off of deferred tax assets pursuant to set-off provisions
Net deferred tax liabilities
Movements in deferred tax liabilities
Opening balance at 1 July
Credited to the income statement
Closing balance at 30 June
Deferred tax liabilities to be recovered after more than 12-months
Deferred tax liabilities to be recovered within 12-months
9,788
926
187
253
140
51,936
63,230
(9,296)
53,934
9,487
(191)
9,296
6,241
3,055
9,296
2,362
6,929
5
9,296
(9,296)
—
9,487
(191)
9,296
9,173
123
9,296
9,507
—
372
125
68
51,222
61,294
(9,487)
51,807
10,963
(1,476)
9,487
7,248
2,239
9,487
2,475
7,012
—
9,487
(9,487)
—
10,963
(1,476)
9,487
9,487
—
9,487
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
Cash and cash equivalents
Made up as follows:
Corporate cash and bank balances (a)
Joint arrangements (b)
Total cash and cash equivalents
227,684
210,745
14,280
47,512
61,792
9,588
10,579
20,167
289,476
230,912
13,826
21,647
13,296
530
13,826
20,577
1,070
21,647
(a) $2,920,000 of this balance relates to cash held with Macquarie Bank Limited to be used for allowable purposes under the Facility
Agreement (2022: $4,725,000), 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.
The Group’s exposure to credit and interest rate risk is discussed in Note 32.
Current
Trade debtors
Accrued income and recoveries (a)
Other receivables
Prepayments
Items measured at amortised cost:
Deferred receivable from partial sale of producing assets (b)
55
3,963
545
1,361
751
6,675
639
3,533
578
1,302
20,820
26,872
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 32(a)).
(a) Accrued income and recoveries includes revenue recognised from hydrocarbon volumes delivered to respective customers but not yet
invoiced and accrued costs recoverable under Joint Arrangements.
(b) Represents deferred consideration receivable in respect of the disposal of 50% of interests in the Amadeus Basin producing assets
(refer Note 3(b)). This is classified as a Financial Asset measured at amortised cost. During the year, $20,373,000 was recouped
through a free carry by the purchasers of Central’s share of expenditure on certain exploration and development projects (2022:
$9,695,000). An amount of $304,000 (2022: $665,000) was recognised as Other Income as a result of adjustments to amortised cost
for the period.
Crude oil and natural gas
Spare parts and consumables
Drilling materials and supplies at cost
Year ended 30 June 2022
Opening net book amount
Additions
Changes to rehabilitation estimates
Disposals and write offs
Depreciation charge
Closing net book amount
At 30 June 2022
Cost
Accumulated depreciation
Net book amount at 30 June 2022
Year ended 30 June 2023
Opening net book amount
Additions
Changes to rehabilitation estimates
Disposals and write offs
Depreciation charge
Closing net book amount
At 30 June 2023
Cost
Accumulated depreciation
Net book amount at 30 June 2023
108
1,412
2,030
3,550
45
1,228
2,595
3,868
19,185
3,908
3
(778)
(2,598)
19,720
43,327
(23,607)
19,720
19,720
4,469
10
(3)
(2,762)
21,434
47,779
(26,345)
21,434
53,988
10,053
(275)
(3,762)
(6,158)
53,846
101,543
(47,697)
53,846
53,846
12,815
(158)
(3)
(6,308)
60,192
114,173
(53,981)
60,192
930
—
—
—
(176)
754
1,952
(1,198)
754
754
—
—
—
(175)
579
1,952
(1,373)
579
33,873
6,145
(278)
(2,984)
(3,384)
33,372
56,264
(22,892)
33,372
33,372
8,346
(168)
—
(3,371)
38,179
64,442
(26,263)
38,179
At 30 June 2023, $2,891,000 of property plant and equipment balances relates to assets under construction and is not subject to
depreciation until complete (2022: $2,011,000).
In assessing the appropriateness of the recoverability of property, plant and equipment balances, the net book amounts above have been
tested for impairment against expected future cash flows from the producing assets cash generating unit as described in the Goodwill
impairment assessment (Note 15).
The Balance Sheet shows the following amounts relating to leases:
Right-of-use assets
Land & Buildings
Plant & Equipment
Lease Liabilities
Current
Non-current
483
68
551
426
201
627
832
90
922
413
588
1,001
Additions to the right-of-use assets during the 2023 financial year were $77,000 (2022: $24,000). Disposals and incentive adjustments
amounted to $6,000 (2022: $36,000).
At 30 June 2023, the Group has entered into Leases which have not yet commenced. The total expected future cash outflows which the
Group is committed to in respect of those leases amounts to $59,000 over a period of 36 months from the commencement date.
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 2023 was $493,000 (2022: $638,000).
373
69
442
49
—
367
154
521
78
—
The Group leases office space, property easements, equipment and vehicles. Rental contracts are typically made for fixed periods of 3 to 5
years but may have extension options as described below. Lease terms are negotiated on an individual basis and contain a wide range of
different terms and conditions. The lease agreements do not impose any covenants other than the security interests in the leased assets
that are held by the lessor. Leased assets may not be used as security for borrowing purposes.
Contracts may contain both lease and non-lease components. The Group has elected not to separate lease and non-lease components and
instead accounts for these as a single lease component.
Leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use by the
Group. Each lease payment is allocated between the liability and finance cost. The finance cost is charged to profit or loss over the lease
period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period.
Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of the
following lease payments:
•
•
•
•
•
fixed payments (including in-substance fixed payments), less any lease incentives receivable;
variable lease payment that are based on an index or a rate;
amounts expected to be payable by the lessee under residual value guarantees;
the exercise price of a purchase option if the lessee is reasonably certain to exercise that option; and
payments of penalties for terminating the lease, if the lease term reflects the lessee exercising that option.
Extension and termination options are included in some leases across the Group. These are used to maximise operational flexibility in
terms of managing the assets used in the Group’s operations. The extension and termination options held are exercisable only by the
Group and not by the respective lessor. Lease payments to be made under reasonably certain extension options are also included in the
measurement of the liability.
The lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be determined, the lessee’s incremental
borrowing rate is used, being the rate that the lessee would have to pay to borrow the funds necessary to obtain an asset of similar value
in a similar economic environment with similar terms, security and conditions.
To determine the incremental borrowing rate, the Group:
•
•
•
where possible, uses recent third-party financing received by the individual lessee as a starting point, adjusted to reflect changes
in financing conditions since third party financing was received;
uses a build-up approach that starts with a risk-free interest rate adjusted for credit risk for leases held by Central Petroleum
Limited, which does not have recent third-party financing; and
makes adjustments specific to the lease, e.g. term, country, currency and security.
The Group is exposed to potential future increases in variable lease payments based on an index or rate, which are not included in the
lease liability until they take effect. When adjustments to lease payments based on an index or rate take effect, the lease liability is
reassessed and adjusted against the right-of-use asset.
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.
Acquisition costs of right to explore
Movement for the year:
Balance at the beginning of the year
Impairment expense (Note 4(e))
Balance at the end of the year
7,999
8,397
8,397
(398)
7,999
8,397
—
8,397
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
1,025
(646)
379
379
69
(116)
—
332
1,094
(762)
332
848
(546)
302
302
177
(100)
—
379
1,025
(646)
379
Non-Current
Security bonds on exploration permits and rental properties
3,053
4,410
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. Amounts refundable on condition of
meeting performance obligations are measured at amortised cost.
Goodwill arising from business combinations
1,953
1,953
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.
In determining impairment indicators, an assessment of the fair value less cost of disposal is made by estimating future cash flows from
available 2P gas and oil reserves over a 20-year period from balance date, being the period over which the value of existing reserves is
expected to be substantially realised. Cash flows include estimated capital expenditure to enhance production. The future cash flows are
discounted to their present value using a post-tax discount rate, which includes an assessment of asset specific risks and the time value of
money. The calculations require significant management judgement and are subject to risk and uncertainty, and broader economic
conditions.
The following table sets out the key assumptions used in assessing the fair value less cost to sell of producing assets:
Sales volumes
Sales price (% annual growth rate)
Operating costs (% annual growth rate)
Post-tax discount rate (%)
2P Reserves
2.5 – 4.1%
2.5 – 4.1%
11.00%
Management has determined the values assigned to each of the above key assumptions as follows:
Sales volume
Sales price
Operating costs
Capital expenditure
Annual growth rate
Post-tax discount rate
Current
Trade payables
Other payables
Accruals
Natural gas sales are based on both Annual Contract Quantities for existing contracts which continue at
projected nominations and uncontracted volumes taking into account firm plant capacity, and limited to
2P reserve volumes. Gas, crude and condensate volumes are based on projected field production, taking
into account historical production and forecast reservoir decline.
Existing contracts are based on current contracted prices escalated for forecast CPI increases as per the
contract terms. Some contracts contain minimum and maximum increases. Uncontracted gas sales are
based on estimated attainable gas prices taking into account indicative customer proposals. Crude and
condensate pricing is based on a mid-point of independent analyst forecasts of crude prices and a long-
term forecast average USD exchange rate.
Current budgeted operating costs are based on past performance and expectations for the future.
Forecasts are inflated beyond the budget year using inflationary estimates. Other known factors are
included where applicable and known with certainty.
Where further field capital expenditure is required in order to meet contracted and projected sales
volumes, the expected future cash costs are taken into account.
This is the average growth rate used to extrapolate cash flows beyond the budget period. Management
considers forecast inflation rates and industry trends if applicable.
This rate reflects risks relating to the segment which includes the impact of sustainability and climate-
change related factors. Post-tax discount rates have been applied to discount the forecast future post-tax
cash flows.
878
5
2,126
3,009
7,817
4
5,705
13,526
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 32.
(a)
Current1
Debt facilities
(b)
Non-current1
Debt facilities
1 Details regarding interest bearing liabilities are contained in Note 32(e).
4,376
4,500
23,150
26,309
Employee entitlements (a)
Restoration and rehabilitation (b)
Joint Venture production over-lift (c)
4,365
370
862
5,597
763
24,460
1,593
5,128
24,830
2,455
26,816
32,413
4,043
1,512
770
6,325
878
22,120
2,182
4,921
23,632
2,952
25,180
31,505
(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.
(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 previously taken a higher proportion of
natural gas produced from the Mereenie joint venture than its joint venture percentage entitlement. A provision has been recognised
to reflect the expected additional production costs of rebalancing production entitlements between the joint venture partners from
future operations.
Movements in each class of provision during the financial year are set out below:
Carrying amount at start of year
Change in provision charged/(credited) to property,
plant and equipment
Additional provisions charged to profit or loss
Unwinding of discount
Amounts used during the year
Carrying amount at end of year
4,921
—
3,023
—
(2,816)
5,128
23,632
2,952
31,505
(158)
644
837
(125)
—
296
—
(793)
(158)
3,963
837
(3,734)
24,830
2,455
32,413
729,405,268 fully paid ordinary shares (2022: 725,907,449)
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.
Balance at start of year
Shares issued under Employee Incentive Plans
725,907,449
3,497,819
724,093,661
1,813,788
197,776
—
197,776
—
Balance at end of year
729,405,268 725,907,449
197,776
197,776
The following table shows the movement in options over ordinary shares during the year:
Executive Share Option Plan
30 Jun 20231
$0.200
17,221,046
Total
17,221,046
—
—
—
—
—
—
17,221,046
17,221,046
1 The options were available to be exercised up to and including 30 June 2023. All of the unexercised options were subsequently cancelled on 1 July 2023.
Under the Group’s Employee Rights Plan, eligible employees may receive rights to shares in Central Petroleum Limited. Details of the terms
and conditions of the various share rights issued pursuant to the Employee Rights Plan are set out in Section E and Section G of the
Remuneration Report.
The table below sets out the maximum number of share rights outstanding at year end and movements for the year.
Long Term Incentive Plans
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee Deferred Share rights1
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Executive Incentive Plan
03 Oct 2022
22 May 2024
12 Nov 2024
30 Jun 2024
30 Jun 2025
30 Jun 2025
30 Jun 2026
30 Jun 2027
1 Jul 2017
1 Jul 2018
1 Jul 2018
1 Jul 2019
1 Jul 2019
1 Jul 2020
1 Jul 2021
1 Jul 2022
6,849
353,405
578,689
6,308,318
3,692,054
9,074,800
426,192
—
—
—
—
—
—
—
61,476
540,992
—
(11,893)
—
(3,455,606)
(331,483)
(373,731)
(112,767)
(33,812)
(6,849)
(268,635)
—
(2,533,679)
—
—
—
—
—
72,877
578,689
319,033
3,360,571
8,701,069
374,901
507,180
EIP Share Rights
30 Jun 2027
1 Jul 2021
—
8,739,398
(925,927)
— 7,813,471
Non-Executive Director rights 2
Director Share Rights
Director Share Rights
30 Jun 2026
30 Jun 2027
1 Jul 2021
1 Jul 2022
850,421
—
—
924,971
—
—
(688,656)
—
161,765
924,971
Total
21,290,728
10,266,837
(5,245,219)
(3,497,819)
22,814,527
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 1 July 2023.
2 Directors had the discretion to sacrifice up to 25% of their Base Directors Fees to earn share rights. These rights vested on 30 June of the Plan Year and may be
exercised any time prior to the expiry date.
The rights do not entitle the holders to participate in any share issue of the Company or any other entity.
Share options reserve
Movements:
Balance at start of year
Share based payment costs (a)
Transaction costs
Balance at end of year
31,433
30,615
30,615
820
(2)
31,433
29,094
1,524
(3)
30,615
(a) Share based payments are provided to employees under the Employee Rights Plan and Executive Share Option Plan. Refer to Note 31 and Sections E, F and G of
the Remuneration Report for further details of share-based payments.
Movements in accumulated losses were as follows:
Balance at the start of year
Net (loss)/profit for the year
Balance at end of year
(201,861)
(7,960)
(209,821)
(223,181)
21,320
(201,861)
(a)
Basic (loss)/earnings per share (cents)
(b)
Diluted (loss)/earnings per share (cents)
(c)
(Loss)/Profit used in earnings per share calculation
(Loss)/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 loss/earnings per share
Adjustments for the calculation of diluted loss/earnings per share:
(1.09)
(1.09)
2.94
2.88
(7,960)
21,320
728,113,749
725,363,955
Employee share rights
—
15,343,575
Weighted average number of shares used as the denominator in
calculating diluted loss/earnings per share
728,113,749
740,707,530
Options and Rights on issue are considered to be potential ordinary shares and have not been included in the calculation of basic
loss/earnings per share. Additionally, for 2023, any exercise of options or rights would be antidilutive as their exercise to ordinary shares
would decrease the loss per share. In accordance with AASB 133, they are also excluded from the diluted loss per share calculation.
The Group has identified its operating segments based on the internal reports that are reviewed and used by the executive management
team (the chief operating decision makers) in assessing performance and in determining the allocation of resources. The following
operating segments are identified by management based on the nature of the business or venture.
Production and sale of crude oil, natural gas and associated petroleum products from fields that are in the production phase.
Fields under development in preparation for the sale of petroleum products. There were no fields under development during the current
or prior financial year.
Exploration and evaluation of permit areas.
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.
Management monitors the operating results of the operating segments separately for the purpose of making decisions about resource
allocation and performance assessment. Non IFRS measures such as Earnings before interest, depreciation, amortisation and impairment
(EBITDA) are also used by management. Refer to tables and reconciliations below.
The Consolidated Entity’s operations are wholly in one geographical location, being Australia.
Revenue from contracts with customers
Natural gas
Crude oil and condensate
Forfeited take or pay amounts
Total revenue from contracts with
customers
Cost of sales
Gross profit
Other income1
Exploration expenditure
Finance costs
General and administrative expenses2
Statutory profit / (loss) before income tax
Taxes
Statutory profit / (loss) for the year
Add Finance costs net of interest income
Add Depreciation and amortisation expense
Add Exploration expenditure
EBITDAX3
Segment assets
34,731
3,488
1,036
39,255
(26,408)
12,847
556
(6,862)
(4,446)
—
2,095
—
2,095
3,965
6,295
6,862
19,217
72,694
—
—
—
—
—
—
977
(6,231)
(63)
—
(5,317)
—
(5,317)
54
—
6,231
968
—
—
—
—
—
—
347
—
(288)
(4,797)
(4,738)
—
(4,738)
(59)
571
—
(4,226)
11,618
13,819
34,731
3,488
1,036
39,255
(26,408)
12,847
1,880
(13,093)
(4,797)
(4,797)
(7,960)
—
(7,960)
3,960
6,866
13,093
15,959
98,131
Segment liabilities
(64,310)
(5,768)
(8,665)
(78,743)
Capital expenditure
Property, plant and equipment
Intangibles
Total capital expenditure
12,690
56
12,746
—
—
—
125
13
138
12,815
69
12,884
1 Other Income attributable to the Exploration Assets segment includes $795,000 relating to the Peak Helium Farmout (Refer Note 3(a)).
2
3 EBITDAX is earnings before interest, taxation, depreciation, amortisation, impairment and exploration expense.
Includes share based payments of $820,000 which is a non-cash item.
Revenue from contracts with customers
Natural gas
Crude oil and condensate
Total revenue from contracts with
customers
Cost of sales
Gross profit
Other income1
Exploration expenditure
Finance costs
General and administrative expenses2
Statutory profit / (loss) before income tax
Taxes
Statutory profit / (loss) for the year
Add Finance costs net of interest income
Add Depreciation and amortisation
Add Exploration expenditure
EBITDAX3
Segment assets
36,255
5,896
42,151
(27,351)
14,800
37,227
(15,748)
(3,963)
—
32,316
—
32,316
3,962
6,095
15,748
58,121
91,954
—
—
—
—
—
10
(5,899)
(41)
—
(5,930)
—
(5,930)
41
—
5,899
10
—
—
—
—
—
—
—
(220)
(4,846)
(5,066)
—
(5,066)
221
684
—
(4,161)
36,255
5,896
42,151
(27,351)
14,800
37,237
(21,647)
(4,224)
(4,846)
21,320
—
21,320
4,224
6,779
21,647
53,970
13,038
17,302
122,294
Segment liabilities
(73,212)
(13,741)
(8,811)
(95,764)
Capital expenditure
Property, plant and equipment
Intangibles
Total capital expenditure
9,695
122
9,817
—
—
—
358
55
413
10,053
177
10,230
Includes share based payments of $1,524,000 which is a non-cash item.
1 Other income in the Producing Assets segment includes $36,559,000 profit on disposal of 50% interest in Amadeus Basin producing properties (Refer Note 3(b)).
2
3 EBITDAX is earnings before interest, taxation, depreciation, amortisation, impairment and exploration expense.
4 FY2022 restated to reflect expenses by function (refer Note 1(a)).
Revenue from external customers by geographical location of production:
Australia
Non-current assets by geographical location:
Australia
39,255
42,151
74,080
69,907
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
15,068
5,762
4,183
3,923
—
38%
15%
11%
10%
—
13,622
7,850
6,478
4,478
4,414
32%
19%
15%
11%
10%
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
Profit/(loss) for the year
Total comprehensive profit/(loss)
15,098
18,311
33,409
(6,609)
(1,144)
(7,753)
25,656
197,776
31,433
(203,553)
25,656
2,227
2,227
23,128
19,162
42,290
(18,129)
(1,550)
(19,679)
22,611
197,776
30,615
(205,780)
22,611
(223)
(223)
Guarantees have been provided by the Parent Entity to subsidiaries arising out of the course of ordinary operations.
A loan facility exists under which the Parent Entity and non-borrowing subsidiaries have provided guarantees to a financier in relation to
the repayment of monies owing and other performance related obligations of the Borrower typical for a borrowing of this nature. Monies
received through the operation of the Palm Valley, Dingo and Mereenie fields are subject to a proceeds account and can be distributed to
the Parent Entity as available when no default exists. Revenues resulting from operations outside of these assets (such as the Surprise field)
are not subject to a cash sweep or other restrictions under the Facility where no defaults exist.
The Parent Entity is Central Petroleum Limited.
The consolidated financial statements include the financial statements of Central Petroleum Limited and the subsidiaries listed in the
following table:
Merlin Energy Pty Ltd
Central Petroleum Projects Pty Ltd
Helium Australia Pty Ltd
Ordiv Petroleum Pty Ltd
Frontier Oil & Gas Pty Ltd
Central Petroleum Eastern Pty Ltd
Central Geothermal Pty Ltd
Central Petroleum Services Pty Ltd
Central Petroleum PVD Pty Ltd
Central Petroleum (NT) Pty Ltd
Jarl Pty Ltd
Central Petroleum Mereenie Pty Ltd
Central Petroleum Mereenie Unit Trust
Central Petroleum WS (NO 1) Pty Ltd
Central Petroleum WS (NO 2) Pty Ltd
Short-term employee benefits
Post-employment benefits
Long-term benefits
Share based payments
Western Australia
Western Australia
Victoria
Western Australia
Western Australia
Western Australia
Western Australia
Western Australia
Queensland
Queensland
Queensland
Queensland
N/A
Queensland
Queensland
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Units
Ordinary
Ordinary
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
2,944,399
165,023
37,775
520,613
3,531,962
180,208
43,807
1,158,763
3,667,810
4,914,740
Detailed remuneration disclosures are provided in the remuneration report on pages 33 to 48.
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
Merlin Energy Pty Ltd
Frontier Oil & Gas Pty Ltd
Central Geothermal Pty Ltd
Central Petroleum PVD Pty Ltd
Jarl Pty Ltd
Central Petroleum WS (NO 1) Pty Ltd
The above companies represent a ‘closed group’ for the purposes of the instrument, and as there are no other parties to the deed of cross
guarantee that are controlled by Central Petroleum Limited, they also represent the ‘extended closed group’.
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 2023.
Revenue from the sale of goods
Cost of sales
Gross profit
Other income
Exploration expenses
Finance costs
General and administrative expenses
(Loss)/profit before income tax
Income tax credit/(expense)
(Loss)/Profit for the year
Other comprehensive profit/(loss) for the year, net of tax
Total comprehensive (loss)/profit for the year
Accumulated losses at the beginning of the financial year
(Loss)/profit for the year
Accumulated losses at the end of the financial year
* FY2022 restated to reflect expenses by function (refer Note 1(a)).
20,783
(15,952)
4,831
1,854
(13,011)
(1,626)
(4,376)
(12,328)
1,567
(10,761)
—
(10,761)
(210,853)
(10,761)
(221,614)
13,645
(8,641)
5,004
29,875
(21,647)
(1,740)
(4,291)
7,201
(10)
7,191
—
7,191
(218,044)
7,191
(210,853)
Set out below is a consolidated balance sheet of the closed group as at 30 June.
ASSETS
Current assets
Cash and cash equivalents
Trade and other receivables
Inventories
Total current assets
Non-current assets
Property, plant and equipment
Right of use assets
Exploration assets
Other 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
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
13,718
4,806
2,613
21,137
30,323
512
7,999
265
2,259
5,178
1,953
48,489
69,626
14,113
1,006
2,639
396
4,508
22,662
11,572
12,163
186
15,448
39,369
62,031
7,595
21,410
21,557
3,075
46,042
24,997
858
8,397
314
2,728
5,064
1,953
44,311
90,353
22,958
992
2,821
386
5,098
32,255
11,824
14,266
543
13,927
40,560
72,815
17,538
197,776
31,433
(221,614)
7,595
197,776
30,615
(210,853)
17,538
Profit after income tax
Adjustments for:
Depreciation and amortisation
Impairment
Lease incentive
Profit on disposal of assets
Exploration costs funded by Joint Venture partners
Share-based payments
Financing costs and interest (non-cash)
Changes in assets and liabilities relating to operating activities:
Decrease in trade and other receivables
Decrease/(increase) in inventories
(Decrease)/increase in trade and other payables
Decrease in deferred revenue
Increase in provisions
Net cash (outflow)/inflow from operations
(7,960)
21,320
6,866
3,486
—
—
7,421
820
1,641
129
317
(10,681)
(4,324)
229
(2,056)
6,779
—
30
(36,559)
7,572
1,524
1,150
358
(2,330)
7,781
(4,155)
170
3,640
During the year, the purchasers of 50% of the Group’s interests in the Amadeus Basin producing properties funded $9,863,000 (2022:
$2,040,000) of the Group’s share of costs for the acquisition of property, plant and equipment. These amounts form part of the deferred
consideration component of the sale proceeds (refer Note 3 (b)).
Non-cash investing and financing activities disclosed in other notes are:
Acquisition of right of use assets – Note 11(a); and
Options and rights issued to employees under short and long term incentive plans – Note 31.
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.
Cash and cash equivalents (including cash classified as held for sale)
Borrowings and leases – repayable within one year
Borrowings and leases – repayable after one year
Net debt
Cash
Gross Debt – fixed interest rates
Gross debt – variable interest rates
Net debt
13,826
(4,802)
(23,351)
(14,327)
13,826
(627)
(27,526)
(14,327)
21,647
(4,913)
(26,897)
(10,163)
21,647
(1,001)
(30,809)
(10,163)
Net debt 1 July 2021
Cash flows
Other non-cash movements
Net debt 30 June 2022
Cash flows
Amortisation of deferred borrowing costs
Non-cash lease adjustments
37,165
(15,518)
—
21,647
(7,821)
—
—
(66,809)
36,000
—
(30,809)
3,625
(342)
—
Net debt 30 June 2023
13,826
(27,526)
(1,659)
561
97
(31,303)
21,043
97
(1,001)
(10,163)
445
—
(71)
(627)
(3,751)
(342)
(71)
(14,327)
The Consolidated Entity had contingent liabilities at 30 June 2023 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 (2022: $1,000,000) within 12-months following the commencement of any future commercial production from the
permits. No commercial production is currently forecast from this permit.
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.
Under the resulting business combination transaction, a fair value of Nil was ascribed to this contingent liability. No change has
been made to the fair value in subsequent years.
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.
The Consolidated Entity has the following capital expenditure commitments:
The following amounts are due:
Within one year
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
1,241
1,241
982
982
11,200
18,454
—
29,654
39,398
38,799
—
78,197
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.
An Executive Share Option Plan operated in respect of the three year period from FY2020 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.
20 Aug 2019
07 Nov 2019
30 Jun 20231
30 Jun 20231
12,116,046
5,105,000
Totals
17,221,046
Weighted average exercise price
$0.20
20 Aug 2019
07 Nov 2019
30 Jun 2023
30 Jun 2023
13,046,116
5,105,000
Totals
18,151,116
Weighted average exercise price
$0.20
—
—
—
—
—
—
—
—
$0.20
$0.20
$0.120
$0.087
$0.111
—
—
12,116,046
5,105,000
—
17,221,046
—
$0.20
$0.20
$0.20
$0.120
$0.087
(930,070)
—
12,116,046
5,105,000
$0.111
(930,070)
17,221,046
—
$0.20
—
—
—
—
—
—
—
—
1 The options were exercisable up to and including 30 June 2023. No options were exercised and they were subsequently cancelled on
1 July 2023.
The weighted average remaining contractual life at 30 June 2023 was Nil years (2022: 1 year). The values of Executive Options were
calculated at the date of grant using a Black Scholes valuation.
Under the Group’s Short Term Incentive Plan, the Board may issue share rights in lieu of cash payments. No share rights were issued in
respect of the Short Term Incentive Plan during the current or prior financial year.
11 Nov 2020
30 Jun 20201
3,692,054
11 Nov 2020
30 Jun 20201
3,692,054
—
—
$0.130
—
(331,483)
3,360,571
$0.130
—
—
3,692,054
1 Share rights in respect of the performance period ended 30 June 2020 have a deferred vesting date of 1 July 2023.
The weighted average remaining contractual life of outstanding STIP share rights at the end of the year was 2.0 years (2022: 3.0 years).
Under the Non-Executive Director offers for FY2023 and FY2022, Directors could agree to receive a maximum of 25% of their Base Fee in
the form of Share Rights. By agreeing to the offer, the Directors agreed to waive any entitlement to receive cash fees to the extent of the
value of the Share Rights granted. The Share rights automatically vested on 30 June of the financial year. The following Non-Executive
Director Share Rights movements occurred during the year:
23 Nov 2022
30 Jun 2023
850,421
924,971
$0.084
(688,656)
23 Nov 2021
30 Jun 2022
—
850,421
$0.115
—
—
1,086,736
850,421
The weighted average remaining contractual life of outstanding Non-Executive Director share rights at the end of the year was 3.9 years
(2022: 4.0 years).
From FY2022, Key Management Personnel were eligible to participate in the EIP, an integrated incentive plan 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:
i)
ii)
33% is paid at that time (i.e. at the end of the initial 12-month performance period); and
The 67% balance of the awarded incentive value is granted as Service Rights that vest over the next three years in equal tranches
beginning 12-months after the end of the initial 12-month performance period.
The 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 following EIP movements occurred during the year:
19 Sep 2022 30 Jun 2022
10 Nov 2022 30 Jun 2022
Totals
—
—
—
5,579,045
3,160,353
8,739,398
$0.096
$0.083
$0.091
—
—
—
(925,927)
—
(925,927)
1,725,352
1,053,451
2,927,766
2,106,902
2,778,803
5,034,668
The weighted average fair value of share rights issued to key management personnel during the financial year was $0.091. The weighted
average remaining contractual life of outstanding Executive Incentive Plan share rights at the end of the year was 4.0 years.
At 30 June 2023, no rights had been granted under the EIP for the plan year ended 30 June 2023. Share rights, as part of the FY2023 EIP
are expected to be granted during FY2024. The grant date is yet to be determined.
Under the Group’s Employee Rights Plan, eligible employees may receive rights to shares of Central Petroleum Limited. The rights are
granted in respect of a plan year which commences 1 July each year. The share rights remain unvested for three years commencing from
the start of each plan year. Except in limited circumstances, eligible employees must still be in the employment of Central Petroleum
Limited as at the vesting date for the rights to vest.
The number of rights to be granted to eligible employees is determined based on the maximum long term incentive amount applicable for
each employee, being either a fixed dollar amount or a percentage of the employee’s base salary, divided by the volume weighted average
share price at the start of the plan year.
Final vesting percentages for those employees on a percentage based, share-price linked plan are determined by a combination of
performance hurdles in respect of a combination of absolute total shareholder return and relative total shareholder return compared to a
specific group of exploration and production companies.
Rights for participants in the fixed $1,000 Exempt Plan vest at the end of the three year service period.
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:
22 Aug 2022 30 Jun 2023
22 Aug 2022 30 Jun 2022
17 Aug 2021 30 Jun 2022
18 Sep 2020 30 Jun 2018
30 Jun 2021
24 Jul 2020
30 Jun 2021
24 Jul 2020
30 Jun 2020
24 Jul 2020
07 Nov 2019 30 Jun 2019
23 Aug 2019 30 Jun 2020
23 Aug 2019 30 Jun 2020
09 May 2019 30 Jun 2019
24 Sep 2019 30 Jun 2019
24 Sep 2019 30 Jun 2019
01 Sep 2017 30 Jun 2018
—
—
426,192
1,198
8,620,660
454,140
30,545
578,689
274,119
6,003,654
28,012
259,406
65,987
5,651
540,992
61,476
—
—
—
—
—
—
—
—
—
—
—
—
$0.090
$0.090
$0.105
$0.130
$0.065
$0.089
$0.089
$0.119
$0.190
$0.155
$0.101
$0.087
$0.120
$0.115
—
—
—
(1,198)
—
—
(26,553)
—
(220,611)
(2,286,515)
—
(251,279)
(17,356)
(5,651)
(33,812)
(6,219)
(106,548)
—
(260,361)
(113,370)
(3,992)
—
(29,520)
(3,422,094)
—
—
(11,893)
—
507,180
55,257
319,644
—
8,360,299
340,770
—
578,689
23,988
295,045
28,012
8,127
36,738
—
Totals
16,748,253
602,468
(2,809,163)
(3,987,809)
10,553,749
The weighted average fair value of share rights granted under the Long Term Incentive Plan during the year was $0.09 (2022: $0.105). The
weighted average remaining contractual life of outstanding share rights at the end of the year was 2.1 years (2022: 2.7 years).
The fair values of deferred share rights granted are valued using methodology that takes into account market and peer performance
hurdles if applicable. The value of share rights with performance hurdles are calculated at the date of grant using a Black Scholes valuation
model and Monte Carlo simulations and an agreed comparator group to assess relative total shareholder return. Other share rights are
valued at the value of an equivalent ordinary share at the grant date.
17 Aug 2021 30 Jun 2022
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
23 Aug 2019 30 Jun 2020
23 Aug 2019 30 Jun 2020
09 May 2019 30 Jun 2019
17 Apr 2019 30 Jun 2019
17 Apr 2019 30 Jun 2019
24 Sep 2019 30 Jun 2019
24 Sep 2019 30 Jun 2019
01 Sep 2017 30 Jun 2018
—
1,198
9,417,632
499,488
30,545
1,837,109
311,019
6,480,842
756,584
28,793
2,566
5,176,154
292,883
12,500
450,780
—
—
—
—
—
—
—
—
—
—
—
—
—
$0.105
$0.130
$0.065
$0.089
$0.089
$0.119
$0.190
$0.155
$0.101
$0.111
$0.150
$0.087
$0.120
$0.115
—
—
—
—
—
—
—
—
(31,848)
(9,069)
(2,566)
(1,549,532)
(220,773)
—
(24,588)
—
(796,972)
(45,348)
—
(1,258,420)
(36,900)
(477,188)
(696,724)
(19,724)
—
(3,367,216)
(6,123)
(6,849)
426,192
1,198
8,620,660
454,140
30,545
578,689
274,119
6,003,654
28,012
—
—
259,406
65,987
5,651
Totals
24,847,313
450,780
(1,813,788)
(6,736,052)
16,748,253
No rights were granted to key management personnel under the Long Term Incentive Plan during the current or prior financial year.
Total expenses arising from share-based transactions recognised during the year were:
Share Rights issued to employees
820,165
1,524,197
The Consolidated Entity’s principal financial instruments are cash and short-term deposits. The Consolidated Entity also has other financial
assets and liabilities such as trade receivables, trade payables and borrowings, which arise directly from its operations. The Consolidated
Entity’s risk management objective with regard to financial instruments and other financial assets include gaining interest income and the
policy is to do so with a minimum of risk.
The Group manages its exposure to key financial risks primarily through supervision by the Audit and Financial Risk Committee. One of the
primary functions of this Committee is to assist the Board to fulfil its responsibility to exercise due care, diligence and skill with respect to
the oversight and integrity of the management of financial risks and internal controls.
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 2023 is nil (2022: nil), no loss allowance provision has been recorded at 30 June 2023 (2022: nil).
The Group has impaired a receivable amounting to $3,088,000 (2022: nil) which arose during the financial year in relation to the farmout of
interests in certain exploration assets. Further details are set out in Note 4(e).
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 trade receivables at reporting date was:
Current: 0-30 days
4,563
4,750
4,563
4,750
—
—
—
—
The trade receivables at 30 June 2023 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 24(b)). Such guarantees are only provided in exceptional circumstances
and are subject to specific Board approval.
Prudent liquidity risk management implies maintaining sufficient cash, marketable securities and funding facilities. Management monitors
rolling forecasts of the Group’s liquidity reserve (comprising the undrawn borrowing facilities below) and cash and cash equivalents
(Note 7) based on expected cash flows. This is carried out at the Group level in accordance with practice and limits set by the Board of
Directors. The Group’s objective when managing capital is to safeguard the ability to continue as a going concern to ultimately add value
for shareholders through the exploitation and production of hydrocarbon resources.
In addition, the Group’s liquidity management policy involves projecting cash flows, monitoring balance sheet liquidity ratios and
maintaining debt financing plans. In order to satisfy the capital requirements of the Group, the Company may issue new shares or other
equity instruments.
The following are the contractual maturities of financial assets and liabilities:
≤
≥
Financial Assets
Cash and cash equivalents
Trade and other receivables
Other financial assets
Financial Liabilities
Trade and other payables
Interest bearing liabilities
13,826
5,314
—
19,140
(3,009)
(3,997)
—
—
—
—
—
—
—
3,053
3,053
—
(3,811)
(26,171)
(7,006)
(3,811)
(26,171)
—
—
—
—
—
(65)
(65)
13,826
5,314
3,053
22,193
13,826
5,314
3,053
22,193
(3,009)
(34,044)
(3,009)
(28,153)
(37,053)
(31,162)
≤
≥
Financial Assets
Cash and cash equivalents
Trade and other receivables
Other financial assets
Financial Liabilities
Trade and other payables
Interest bearing liabilities
21,647
25,252
—
46,899
(13,526)
(3,706)
—
621
—
621
—
—
—
4,410
4,410
—
(3,644)
(30,495)
(17,232)
(3,644)
(30,495)
—
—
—
—
—
(68)
(68)
21,647
25,873
4,410
51,930
21,647
25,570
4,410
51,627
(13,526)
(37,913)
(13,526)
(31,810)
(51,439)
(45,336)
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:
Financial Assets:
Cash and cash equivalents
4.2
Trade and other receivables —
0.7
Other financial assets
Total Financial Assets
Financial Liabilities:
Trade and other payables
Interest bearing liabilities
0.9
—
0.2
13,826
—
—
21,647
—
—
13,826
21,647
—
—
528
528
—
—
785
785
—
4,563
2,525
—
4,750
3,625
13,826
4,563
3,053
21,647
4,750
4,410
7,088
8,375
21,442
30,807
—
9.8
—
7.3
—
(27,526)
—
(30,809)
—
(627)
—
(1,001)
(3,009)
—
(13,526)
—
(3,009)
(28,153)
(13,526)
(31,810)
Total Financial Liabilities
(27,526)
(30,809)
(627)
(1,001)
(3,009)
(13,526)
(31,162)
(45,336)
Net Financial Assets /
(Liabilities)
(13,700)
(9,162)
(99)
(216)
4,079
(5,151)
(9,720)
(14,529)
A sensitivity of 50 basis points (0.5% pa) has been selected as this is considered a reasonable, scalable benchmark given the current level
and volatility of both short term and long term interest rates. A movement in interest rates of 0.5% pa at the reporting date would have
increased/(decreased) equity and profit and loss by the amounts shown below based on the average balance of interest-bearing financial
instruments held. This analysis assumes that all other variables remain constant.
The analysis is performed only on those financial assets and liabilities with floating interest rates and comparatives for 2022 have been
restated on the same basis.
Cash and cash equivalents
Interest bearing liabilities
Cash and cash equivalents
Interest bearing liabilities
69
(141)
102
(154)
(69)
141
(102)
154
—
—
—
—
—
—
—
—
These movements would not have any impact on equity other than retained earnings.
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.
The Group has a loan facility agreement (Facility) with Macquarie Bank Limited (Macquarie).
Interest costs are based on fixed spreads over the periodic Bank Bill Swap (BBSW) average bid rate. The Facility is structured as a partially
amortising term loan and has a maturity date of 30 September 2025. Repayments comprise fixed quarterly principal repayments along with
accrued interest. The Group does not have any interest rate hedging arrangements in place.
Under the terms of the Facility, the Group is required to comply with the following two key financial covenants:
1.
2.
The Group Current Ratio is at least 1:1, excluding amounts payable under the Facility and certain liabilities associated with gas sales
agreements with Macquarie.
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.
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
-
CAD
281
(46)
(90)
457
(1,082)
—
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
(13)
16
57
(69)
These movements would not have any impact on equity other than retained earnings.
The carrying amounts of cash, cash equivalents, financial assets and financial liabilities, approximate their fair values. Borrowings are
carried at amortised cost, but fair value is not deemed to be materially different from the carrying amount, as interest payable on the
financing facilities reflects current market rates.
Details of joint arrangements in which the Consolidated Entity has an interest are as follows:
OL4, OL5 and PL2 - Mereenie
Oil & gas production
OL3 - Palm Valley
L7 and PL30 - Dingo
EP 82
EP 105
EP 112
EP 125
EPA 111
EPA 124
Gas production
Gas production
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration – application
Oil & gas exploration – application
ATP 2031 - Range Gas Project
Oil & gas exploration
25.00
50.00
50.00
29.00
60.00
35.00
24.00
50.00
50.00
50.00
25.00
50.00
50.00
60.00
60.00
45.00
30.00
50.00
50.00
50.00
The Joint Arrangements are accounted for based on contributions made to the Joint Operated Arrangements on an accruals basis. The
principal place of business is Australia.
Other parties’ rights to earn and retain participating interests in certain permits is subject to satisfying various obligations in their
respective farmout agreements. The participating interests as stated above assume such obligations have been met, or otherwise may be
subject to change or negotiation.
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
530
3,412
3,161
—
7,103
51,173
88
—
51,261
2,834
32
1,371
862
300
—
5,399
11,632
68
1,594
19,885
33,179
19,786
1,070
3,063
3,300
—
7,433
44,086
113
2,432
46,631
7,996
28
1,357
770
1,445
—
11,596
11,857
96
2,182
18,165
32,300
10,168
39,255
72
(34,629)
35,973
7
(37,301)
4,698
(1,321)
In August 2023, the Group reached agreement to progress towards a final investment decision for construction of a helium recovery unit at
Mereenie, demonstrating the potential of the Amadeus Basin as a world-class helium resource.
No matters or circumstances have arisen between 30 June 2023 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.
1.
In the Directors’ opinion:
a) the financial statements and notes set out on pages 51 to 97 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 2023 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 2023.
3. As at the date of this declaration, there are reasonable grounds to believe that the members of the Closed Group identified in
Note 26 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
19 September 2023
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 2023 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 2023
the consolidated statement of comprehensive income for the year then ended
the consolidated statement of changes in equity for the year then ended
the consolidated statement of cash flows for the year then ended
the notes to the consolidated financial statements, which include significant accounting policies
and other explanatory information
the directors’ declaration.
Basis for opinion
We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under
those standards are further described in the Auditor’s responsibilities for the audit of the financial
report section of our report.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis
for our opinion.
Independence
We are independent of the Group in accordance with the auditor independence requirements of the
Corporations Act 2001 and the ethical requirements of the Accounting Professional & Ethical
Standards Board’s APES 110 Code of Ethics for Professional Accountants (including Independence
Standards) (the Code) that are relevant to our audit of the financial report in Australia. We have also
fulfilled our other ethical responsibilities in accordance with the Code.
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
PricewaterhouseCoopers, ABN 52 780 433 757
480 Queen Street, BRISBANE QLD 4000, GPO Box 150, BRISBANE QLD 4001
T: +61 7 3257 5000, F: +61 7 3257 5999
Liability limited by a scheme approved under Professional Standards Legislation
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
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 $0.98m, which represents
approximately 1% of the Group’s total assets.
We applied this threshold, together with
qualitative considerations, to determine the
scope of our audit and the nature, timing and
extent of our audit procedures and to evaluate
the effect of misstatements on the financial
report as a whole.
We chose Group total assets because, in our
view, it is the benchmark against which the
performance of the Group is most commonly
measured and is a generally accepted
benchmark in the oil and gas industry for entities
at a similar stage of development.
We utilised a 1% threshold based on our
professional judgement, noting it is within the
range of commonly acceptable thresholds.
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. We communicated the key audit matters to the Audit
and Financial Risk Committee.
Key audit matter
How our audit addressed the key audit matter
Basis of Preparation of the financial report
Refer to note 1 (a) (i) of the financial report
In assessing the appropriateness of the Group’s going
concern basis of preparation for the financial report, we
performed the following procedures, amongst others:
As described in Note 1 of the financial report, the financial
statements have been prepared by the Group on a going
concern basis, which contemplates that the Group will
continue to meet its commitments, realise its assets and
settle its liabilities in the normal course of business.
Assessing the appropriateness of the Group’s basis of
preparation for the financial report was a key audit matter
due to its importance to the financial report and the level of
judgement involved in assessing future funding and status
of the three well sub-salt exploration program, in particular
with respect to the Group forecasting future cash flows for a
period of at least 12 months from the audit report date (cash
flow forecasts).
evaluated the appropriateness of the Group's
assessment of their ability to continue as a going
concern, including whether the level of analysis is
appropriate given the nature of the Group, the
period covered is at least 12 months from the date
of our auditor’s report and relevant information of
which we are aware as a result of the audit has
been included.
enquired of management and the board of
directors as to their knowledge of events or
conditions that may cast significant doubt on the
Group's ability to continue as a going concern.
evaluated the Group’s plans for future actions
(including alternative options in relation to the
current exploration permits), whether the outcome
is likely to improve the situation and whether they
are feasible in the circumstances.
evaluated selected data and assumptions used in
the Group’s cash flow forecasts for at least 12
months from the date of signing the auditor’s
report.
developed an understanding of what forecast
expenditure in the cash flow forecast is committed
and what could be considered discretionary.
read the terms associated with the debt agreement
and assessed the amount of the facility available
for drawdown and projected debt compliance over
the forecast period.
requested written representations from
management regarding their plans for future action
and the feasibility of these plans.
evaluated whether, in view of the requirements of
Australian Accounting Standards, the financial
report provides adequate disclosures about these
events or conditions.
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 2023, 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 through our opinion on the financial report. We
have issued a separate opinion on the remuneration report.
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.
Report on the remuneration report
Our opinion on the remuneration report
We have audited the remuneration report included in pages 33 to 48 of the directors’ report for the year
ended 30 June 2023.
In our opinion, the remuneration report of Central Petroleum Limited for the year ended 30 June 2023
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
19 September 2023
The 20 largest registered holders of the quoted securities as at 14 September 2023 were:
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
20
20
20
Norfolk Enchants Pty Ltd
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