2024
ANNUAL
REPORT
Central Petroleum Limited
ACN 083 254 308
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.
Dear Shareholders,
This is my fourth annual letter to Central Petroleum’s shareholders, and I have a sense that Central’s outlook is more positive than ever
before. Over the last decade, your company has been through a number of transformations, with the most significant being the substantial
investment in upgrading production capacity leading up to the opening of the Northern Gas Pipeline in 2019.
Since then, the company has prioritised repayment of the various forms of debt that were necessarily raised to fund the expansion
programs. This year we have seen three important developments which should result in sustainable positive cash flows and, ultimately,
returns to shareholders.
Firstly, we have seen a shift in gas markets, particularly in the Northern Territory where a supply-side shortage has seen Central’s onshore
gas fields now more critical than ever to the region’s energy balance, supplying about half of the Northern Territory’s gas demand.
Central’s proven reserves and history of reliable production resulted in a successful marketing campaign that will see all of our firm gas
production sold at attractive pricing into the Northern Territory from 2025 through to the end of 2030. The importance of these new
contracts cannot be understated, with a step change in pricing from maturing legacy gas contracts promising increased free cash flow. The
contracts greatly reduce our exposure to pipeline outage risks which impacted our results this year and clouded our future.
Secondly, our decision to exit from the Range gas project in Queensland has reduced our future capital commitments and consequentially
has strengthened our balance sheet, with $12.5 million in cash proceeds reducing our net debt. At the end of the year we were in a positive
net cash position – for the first time in a decade!
And lastly, we have fully repaid one of our layers of ‘debt’, the pre-sold gas which was used to fund new production wells three years ago.
We are now selling this gas volume, previously dedicated to repaying the debt, into the stronger market, giving us a boost in free cash flow.
A further cash flow boost will arrive in just over 18 months, when we will have fully delivered all of our overlifted gas liability.
Our stronger balance sheet, when combined with the contractual certainty from the new multi-year, Northern Territory-focused gas
contracts and stronger market pricing, gives us increasing confidence to fund new development wells, underwrites debt restructuring and
provides the opportunity for the board to consider returns to shareholders. We are hopeful this will occur in the near term.
The value of Central’s producing assets is becoming more obvious in the gas-short market, and the recent transaction, which saw New
Zealand Oil & Gas (now Echelon Resources) and Horizon Oil purchase Macquarie’s 50% interest in the Mereenie gas field, confirms the
value that we see in these assets.
While our producing assets look set to contribute increasing free cash flows in coming years, we are also working to realise value from our
extensive exploration holdings. The helium, hydrogen and natural gas potential of the sub-salt prospects could be company-changing, and
the potential value of these prospects is too great to ignore. Our strategy is to fund programs from farmouts where possible to spread the
risk and costs while preserving some upside for our shareholders.
The underlying financial results for the year unfortunately reflected the pipeline-induced disruptions to production, which were both
unexpected and outside of Central’s control. However, the new gas sales contracts mentioned earlier will largely neutralise that risk in the
foreseeable future.
With our strategic review completed and outcomes being actioned, we farewelled Director Troy Harry from the Board and I thank him for
his significant contribution and welcome his ongoing support as Central’s largest shareholder.
I also thank our CEO Leon Devaney, together with his management team and staff, for their contributions in safely and efficiently operating
our three gas fields. We also greatly appreciate the continuing support and cooperation of the people, suppliers, local communities and
traditional owners of the land on which we operate. Their combined efforts allow us to continue to provide a reliable and affordable supply
of energy to the businesses and residents of the Northern Territory.
On a closing note, we have responded to the 2023 AGM shareholder vote against our remuneration report by making significant changes to
the remuneration structure of our executive team for FY2025 and beyond. The CEO’s remuneration package has been re-weighted, with
lower fixed remuneration and new at-risk incentives with higher share price appreciation hurdles. The pay of other executives has been
frozen at the 2024 level, and we have retained a smaller executive team (four rather than six) and Board (four Non-executive Directors,
down from five) than we have in the past. Short and long-term incentives have been revised, including an equity-linked component that
now only rewards a significant increase in share price over three years, requiring a circa 50% increase in share price to 8 cents per share
over three years to reach the minimum threshold, and only reaching the maximum award if the share price more than triples to 16 cents
over three years.
In conclusion, we are already seeing some positive outcomes from our extensive strategic review process concluded earlier this year, and
we look forward to sharing news of more success as the next year unfolds.
Thank you,
Mick McCormack, Chair
18 September 2024
Dear fellow Shareholders,
As we reflect on the past year, I am very proud of how our
company has navigated an exceptionally challenging period.
Central, and many of our peers in the gas industry, continued to
face stiff headwinds in the form of ill-conceived gas market
interventions, constricting regulations and determined opposition
from ill-informed, single-interest climate groups.
The reality however, is that gas will play a crucial role in any
affordable transition to cleaner energy. This means that the
demand for gas will continue to be strong for an extended period,
and new gas supply that can be brought to market will be
rewarded. This is what Central is positioned to do.
We also faced the unexpected scenario that shortfalls by other
gas suppliers in the Northern Territory resulted in the Northern
Gas Pipeline, a $1 billion piece of infrastructure linking Northern
Territory gas suppliers to east coast gas customers, experiencing
extended outages over the past two years. Unfortunately, it has
been unavailable for most of this year, and it continues to remain
offline for the foreseeable future. This has had a visible impact on
our FY2024 results and introduced an entirely unexpected risk to
our revenue forecasts.
All of these challenges have put downward pressure on our share
price and have been formidable tests of our resilience and
strategy. Nonetheless, we have emerged stronger and well
positioned to benefit from what we see as tightening gas
markets.
Over the last year we sold our Range project for a profit of $13.8
million (cash proceeds of $12.5 million), providing a significant
boost to our cash balance. We announced a forward strategy
focussed on maximising free cash flow, with exploration
prioritised to activities funded through farmouts. We continued
to pay down our liabilities and have made further cuts to
corporate and administrative costs, including maintaining our
executive headcount at four, down from the six executives
Central has had historically.
Most significant, however, was the successful conclusion of our
gas sale Expression of Interest process which resulted in a new
major gas sale agreement with the Northern Territory
Government. We have now contracted all of our firm gas
production for the next six years, underwritten two new
development wells at Mereenie, and mitigated our exposure to
the Northern Gas Pipeline. I believe this is the most
transformative gas sale agreement that Central has ever
executed, with an increase in our historical average portfolio
contract price and an anticipated increase in Mereenie
production becoming visible early next year.
By exercising rigorous financial discipline and executing robust
commercial strategies, we have the financial strength to both
capitalise on the opportunities ahead and consider returns to
shareholders in the near term.
Accordingly, I am very pleased to report that Central concluded
fiscal year 2024 with a number of highlights, including:
Strong safety record, maintaining a nil TRIFR for more
than 18 months,
Positive net cash position of almost $1m, compared to
net debt of $14.3m just a year ago,
Cost of servicing liabilities is down 60% from just five
years ago,
Net profit of $12.4m with underlying EBITDAX of
$13.8m,
Contracted all existing firm gas for six years into a
strong market,
Mitigated risks associated with the Northern Gas
Pipeline, and
Launched a fully funded two-well drilling program at
Mereenie.
Our progress to return to company-changing exploration has also
been encouraging. We have advanced farmout discussions for
our sub-salt prospects targeting helium and hydrocarbons. We
have also engaged with our joint venture partners in respect of
lower-risk appraisal and exploration within our existing producing
fields, such as new wells at Palm Valley and testing of the
Stairway formation at Mereenie, where any new reserves would
greatly benefit from prevailing gas markets and brownfield
economics.
Our narrower exploration activity is strategically focussed on
high-potential, lower risk areas that can be funded through
farmouts or infield opportunities with compelling risk / reward
metrics. This more affordable and focused exploration activity
supports our strategy to maximise cash flow, whilst retaining
exposure to growth opportunities that can deliver significant
near-term value to our shareholders.
The next 12 months will be a pivotal period for the Company. The
Northern Territory gas market will soon witness drilling results at
the Blacktip field and in the Beetaloo Basin, with the potential for
a shortage in the Northern Territory gas market emerging within
the next six months. We are confident that the actions we have
taken over the past year have solidified shareholder value within
this uncertain landscape and set the foundation for Central to
further leverage changing market dynamics.
We have done the hard work and are now turning the corner on
what has been a challenging period in the Company’s history. I
look forward to our much stronger future becoming more visible
to shareholders over the next year.
Thank you for your continued trust and support. I am confident
that Central can navigate the future successfully and build on this
year’s strong result to deliver shareholder returns into the future.
Sincerely,
Leon Devaney, CEO
18 September 2024
•
Central sold its 50% interest in the Range CSG Project (ATP2031) for $12.5 million, releasing capital and realising a book profit of
$13.8 million.
•
Terminated the farmout of interests in three Northern Territory exploration permits following default by the counterparty,
leading to the deferral of a planned three well exploration program.
•
New gas sales agreements (GSAs) were secured during and subsequent to the end of the financial year, and are expected to
provide higher, more reliable cash flows for Central for several years, benefitting from higher average gas prices and more
consistent, firm sales that will not be affected by any Northern Gas Pipeline (NGP) interruptions, should they occur. The new GSAs
included the sale of (Central share):
-
up to 2.1 PJ to Power & Water Corporation in the NT until the end of 2024 on an as available basis;
-
up to 12 PJ of gas to the Northern Territory Government for six years from 2025 to 2030; and
-
up to 4.1 PJ of gas to Arafura’s Nolan’s rare earth project over three years from 2028, subject to project FID by 31
December 2024.
•
Gas which was pre-sold in 2020 was fully delivered by December 2023, releasing additional gas volumes for sale on usual cash
terms and boosting cash flows from January 2024 onwards.
•
Agreement was reached to progress a helium recovery unit at Mereenie, demonstrating the potential of the Amadeus Basin as a
world-class helium resource. Work continues with parties that include a major helium distributor, with the scope now expanded
to consider a helium liquefaction unit.
Underlying EBITDAX: Decreased 13% to $13.8m in FY2024
(Earnings before interest, tax, depreciation, impairment,
exploration costs, and profit on asset disposals)
Operating revenue: Decreased 5% to $37.2m in FY2024
Bank debt decreased 18% to $23.2m in FY2024.
Net cash: $0.8m at 30 June 2024
The Consolidated Entity had a profit after income tax for the year ended 30 June 2024 of $12.4 million (2023: loss of $8.0 million).
The above result includes a $13.8 million profit on the sale of the Range CSG interests (ATP 2031) and was after expensing exploration costs
of $4.0 million (2023: $13.1 million). The Group’s policy is to expense all exploration costs as incurred.
To assist with comparability of this year’s result, EBITDAX, EBITDA and EBIT have been reported against the underlying results in FY2023.
The table below shows key metrics for the Group:
Net Sales Volumes
-
Natural Gas (TJ)
4,377
4,664
(287)
(6)%
-
Oil & Condensate (bbls)
26,304
30,293
(3,989)
(13)%
Sales Revenue ($‘000)
37,154
39,255
(2,101)
(5)%
Gross Profit ($‘000)
9,789
12,847
(3,058)
(24)%
Underlying EBITDAX1 ($‘000)
13,751
15,749
(1,998)
(13)%
Underlying EBITDA2 ($’000)
9,761
2,656
7,105
268 %
Underlying EBIT3 ($‘000)
1,973
(4,210)
6,183
147 %
Underlying loss after tax4 ($’000)
(1,373)
(8,170)
6,797
83 %
Statutory profit/(loss) after tax ($‘000)
12,422
(7,960)
20,382
256 %
Net cash inflow/(outflow) from Operations5 ($’000)
6,862
(2,056)
8,918
434 %
Capital expenditure6 ($‘000)
2,718
12,815
(10,097)
(79)%
1 Underlying EBITDAX is Earnings before Interest, Tax, Depreciation, Amortisation, Impairment and Exploration costs and profit on disposal of interests in subsidiaries
and exploration permits (refer reconciliation below).
2 Underlying EBITDA is Earnings before Interest, Tax, Depreciation, Amortisation, Impairment and profit on disposal of interests in subsidiaries and exploration
permits.
3 Underlying EBIT is Earnings before Interest, Tax and profit on disposal of interests in subsidiaries and exploration permits.
4 Underlying profit / loss after tax is statutory profit after tax, before profit on disposal of interests in subsidiaries and exploration permits.
5 Cashflow from Operations includes cash outflows associated with exploration activities.
6 Capital expenditure on tangible assets.
Underlying EBITDAX, Underlying EBITDA and Underlying EBIT are non-IFRS measures that are presented to provide an understanding of the
underlying performance of the Group. The non-IFRS information is not subject to audit review, however the numbers have been extracted
from the financial statements which have been subject to review by the Group’s auditor. A reconciliation to profit before tax is provided
below.
EBITDAX
Underlying EBITDAX for the year was $13.8 million, down 13% from $15.7 million in 2023 reflecting lower sales volumes due to intermittent
interruptions to the Northern Gas Pipeline during the year. 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 subsidiaries or exploration permits. 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 $0.7 million this year (2023:
$0.8 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 profit/(loss) before tax
12,422
(7,960)
Impact of farmout to Peak Helium net of impairment costs
—
(210)
Profit on disposal of interest in Range CSG project
(13,795)
—
Underlying loss before tax
(1,373)
(8,170)
Net finance costs and restatement of financial assets
3,346
3,960
Underlying EBIT
1,973
(4,210)
Depreciation, amortisation and impairment
7,788
6,866
Underlying EBITDA
9,761
2,656
Exploration expenses
3,990
13,093
Underlying EBITDAX
13,751
15,749
Sales Volumes
Sales volumes were 7% lower than FY2023 at 4.5 PJe, largely due to
outages on the Northern Gas Pipeline (NGP) interrupting deliveries to
customers in eastern states (oil converted at 5.816 GJ/bbl). The new sale
contracts for the balance of CY2024, and with the NT Government starting
2025 are expected to provide result in more consistent, firm sales that will
not be affected by NGP interruptions.
Gas
PJ
4.4
4.7
Crude and Condensate
bbls
26,304
30,293
Total
PJe
4.5
4.8
Note: Oil is converted to Petajoule equivalent (PJe) at 5.816 GJe/bbl.
Sales Revenue
Central recorded sales revenue of $37.2 million, down 5% on FY2023, reflecting the lower volumes and restricted access to higher-priced
contracts/markets due to the NGP interruptions. Average realised prices were down 4% on FY2023 at $7.56/GJe. Total sales revenue
included $3.0 million released from deferred take-or-pay balances (2023: $1.0 million).
Gross Profit
Gross profit was $9.8 million, a decrease of 24% on FY2023. On a per unit basis this represents a gross profit of $2.16/GJe which is a
decrease of 18% from $2.65/GJe for FY2023, reflecting the lower average sales price and higher per-unit cost of sales. The unit cost of sales
increased by 11%, reflecting fixed costs spread over lower volumes, a 13% increase in royalty expenses on a per unit basis following the
introduction of the new NT royalty regime, and additional environmental regulatory and compliance costs.
Net Assets/Liabilities
At 30 June 2024, the Group had a net asset position of $32.6 million compared to $19.4 million at 30 June 2023, reflecting the current year
profit before share-based payments.
Included in liabilities on the Group’s balance sheet are amounts recognised in respect of deferred revenue associated make-up gas
provisions amounting to $11.3 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, 0.73 PJ of previously
over-lifted gas was repaid to joint venture partners and the remaining 0.44 PJ of pre-sold gas was fully delivered.
Debt
The Group repaid $4.7 million of loan principal during the year. The outstanding balance of the loan facility at 30 June 2024 was
$23.1 million with $4.7 million due for repayment in FY2025. An additional $5.0 million is currently undrawn and available until 30
September 2024.
At 30 June 2024 the Group was in a net cash position of $0.8 million compared to a net debt position of $14.3 million at 30 June 2023,
reflecting the cash received on disposal of the Range CSG project and ongoing cashflow from operations.
The consolidated debt ratio at 30 June 2024 was 0.23 (2023: 0.29). Debt ratio is defined as: Total Debt/Total Assets. Debt service is
supported by long term gas sales contracts and the Group’s certified oil and gas reserves.
Net Cash Flow
Cash balances increased by $11.2 million over the year. Net cash flow from production operations for 2024 was $14.1 million (before
CAPEX), compared to $13.8 million for 2023, with lower sales volumes offset by higher pricing, lower cash production costs and the benefit
of additional cash flows following the end of pre-sold gas deliveries in December 2023.
After net interest payments of $2.0 million, $2.6 million of corporate and staff expenses and $2.6 million for exploration activities, net cash
from operating activities was $6.9 million (2023: $2.1 million outflow).
During the year, Central invested $2.9 million in capital projects, including installation of a compressor to recover flare gas at Mereenie and
other sustaining capital expenditure at the three producing fields. Central repaid $4.7 million of debt during the year.
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 Data1
Operating revenue
65.05
59.83
42.15
39.26
37.15
Exploration expenditure
5.28
7.74
21.65
13.09
3.99
Profit/(loss) after income tax
5.41
0.25
21.32
(7.96)
12.42
EBITDAX
33.40
26.09
53.31
15.96
27.55
Underlying EBITDAX
25.01
26.09
16.75
15.75
13.75
Equity issued during year
.—
.—
—
—
—
Property, plant and equipment2
107.85
108.28
53.85
60.19
55.58
Cash2
25.92
37.17
21.65
13.83
24.99
Borrowings
(70.77)
(66.81)
(30.81)
(27.53)
(23.16)
Net Assets (Total Equity)
1.58
3.69
26.53
19.39
32.56
Net Working Capital (Net current assets/(liabilities))
6.75
8.25
22.31
7.11
16.00
1 In October 2021, Central sold a 50% interest in its producing gas fields
2 Includes assets classified as held for sale.
Operating Data
Gas Sales (TJ)
11,822
9,820
5,993
4,664
4,377
Oil Sales (barrels)
89,016
77,255
47,197
30,293
26,304
No. of employees at 30 June
92
85
88
80
81
Central Petroleum Limited is an ASX-listed oil and gas producer, with a portfolio of producing and prospective tenements across the
Northern Territory (NT). Central is the operator of the largest onshore gas producing fields in the NT, supplying industrial customers,
electricity generators and gas distributors from three producing fields near Alice Springs.
Location of Central’s producing oil and gas fields
Northern Territory
Ownership interests
Central Petroleum (operator)
25.0%
Echelon Mereenie Pty Ltd1
42.5%
Horizon Australia Energy Pty Ltd
25.0%
Cue Mereenie Pty Ltd
7.5%
Gas
PJ
28.1
36.6
45.6
Oil
mmbbl
0.30
0.36
0.05
Total2
PJe
29.8
38.7
45.9
1 Formerly NZOG Mereenie Pty Ltd
2 Reserves and resources are as at 30 June 2024. 2C gas resources include 27 PJ
attributable to the Stairway Sandstone.
3 Oil converted at 5.816 PJ/mmbbl
Central’s share of Mereenie gas and oil production for FY2024 was 2.2 PJe.
Full field gas production for the year was 8.1 PJ, averaging 22.2 TJ/d, down from the 9.5 PJ (26.2 TJ/d) produced in FY2023, impacted by
several temporary shutdowns to the Northern Gas Pipeline during the year. Consequently, oil production was also lower at 294 bbl/d.
A new compressor was commissioned to capture low pressure waste gas and convert it to sales gas, thereby increasing sales and reducing
annual Mereenie CO2 emissions by approximately one-third. The flare gas recovery compressor is intended to increase sales capacity by 0.5
TJ/d and reduce emissions by 13.2 kt CO2-e per year (gross JV).
In response to strong market signals arising from Central’s gas marketing campaign, the Mereenie joint venture has reached a final
investment decision (FID) for two new Mereenie development wells which are forecast to return field production capacity back
above 30 TJ/d (100% JV) and produce at least 25 PJ of gas (100% JV) over their lifetime. Gas from the new wells can be sold into the
new contract with the Northern Territory Government, which can be expanded by up to 6 TJ/d following successful completion of
the wells.
The wells are expected to be drilled in early 2025 and will target the crest of the Pacoota 3 reservoir (at depths of around 1,500m)
to optimise productivity and gas recovery from the field. Project economics are compelling, benefitting from new gas contracts and
low incremental production costs through the use of existing surface infrastructure.
Central and its Mereenie joint venturers continue to work with a major global helium supplier to progress a helium recovery and
liquefaction unit at Mereenie to extract helium from the existing Mereenie gas stream, which typically contains circa 0.2% helium.
Flare gas compressor commissioned, reducing emissions by
up to 33%.
Planning progressing for construction of a helium recovery
and liquefaction unit.
Two new production wells to be drilled in early 2025
Northern Territory
Ownership interests
Central Petroleum (operator)
50.0%
Echelon Palm Valley Pty Ltd1
35.0%
Cue Palm Valley Pty Ltd
15.0%
Gas
PJ
10.9
11.7
6.5
1 Formerly NZOG Palm Valley Pty Ltd
2 Reserves and resources are as at 30 June 2024.
Production from the Palm Valley field averaged 8.9 TJ/d through FY2024, recording an aggregate of 3.3 PJ, consistent with FY2023 sales.
Central’s share of Palm Valley gas sales for FY2024 was 1.6 PJ.
Strong performance from the two most recently drilled wells has led to a 1.9 PJ increase in 2C contingent resources (Central share).
The new six year gas supply agreement with the Northern Territory Government provides a clear market signal to accelerate
investment in field production increases, including drilling new wells at Palm Valley. The Palm Valley joint venture has been
progressing permitting and approvals for two new Palm Valley appraisal wells in advance of a joint venture FID which will require
further gas contracting and funding arrangements by Central.
The deeper Arumbera Sandstone, which is the production reservoir at the Dingo gas field has potential as a significant gas resource
and remains an option for future exploration drilling.
42% increase in 2C contingent gas resources
Planning commenced for new wells to boost production
The Stairway Sandstones which overlie the deeper producing Pacoota Sandstones at Mereenie are estimated to contain 27 PJ of
2C contingent gas resource (net to Central). Gas has previously 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.
The Mereenie Joint Venture is progressing permitting and approvals for up to two Stairway appraisal wells in advance of a joint
venture FID which will require further gas contracting and funding arrangements.
Northern Territory
Ownership interests
Central Petroleum (operator)
50.0%
Echelon Dingo Pty Ltd1
35.0%
Cue Dingo Pty Ltd
15.0%
Gas
PJ
18.7
22.8
—
1 Formerly NZOG Dingo Pty Ltd
2 Reserves and resources are as at 30 June 2024.
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 at Dingo were the highest on record, averaging 3.9 TJ/d across the year, an aggregate of 1.4 PJ (Central share 0.7 PJ), up 18%
on FY2023. The daily contract volume of 4.4 TJ/d is subject to take-or-pay provisions under which Central will be paid in January 2025 for any
gas nomination shortfall by the customer in CY2024.
After a review of field performance and updated modelling, proved and probable (2P) gas reserves were revised upwards by 1.6 PJ (net to
Central, an increase of 7%.
Additional development wells can be drilled in the future at Dingo to maintain contracted gas volumes when warranted by natural field
decline.
The deeper Pioneer Sandstone has flowed gas at the nearby Ooraminna prospect and is an option for future exploration drilling, lying
below the existing Dingo production reservoir and potentially holding significant gas resources.
Record gas production, up 18% on FY2023
2P gas reserves increased by 7%
Central Petroleum holds a significant portfolio of exploration opportunities across the Amadeus, Wiso and Georgina Basins in the Northern
Territory. The total area held by Central for exploration is 173,045 km2 (64,076 km2 granted and 108,969 km2 under application).
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.
Location of sub-salt targets
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 Mereenie, Palm Valley and Dingo gas fields, with higher concentrations of
helium and hydrogen measured in previous exploration wells at Mt Kitty (Jacko Bore), Magee and Dukas. In the context of helium
concentrations of >0.3% being widely considered as helium-rich, a helium concentration of 6% was recorded at the Magee-1 well and gas
flows at Mt Kitty (Jacko Bore 1) contained 9% helium.
Central is seeking to drill several sub-salt appraisal/exploration wells in the Southern Amadeus through farmouts to further test these
prospects. Planning for a seismic acquisition program is also underway for EP115 (including the Zevon lead), following a successful 2D
seismic test line acquired in late 2023 which confirmed a new efficient, low-impact acquisition methodology.
Central is working with a major global helium supplier to progress a helium recovery and liquefaction unit at Mereenie to extract helium
from the existing Mereenie gas stream, which typically contains circa 0.2% helium. Successful production of helium at Mereenie would
provide a new revenue stream for the Mereenie field and demonstrate the potential of the Amadeus Basin as a world-class helium
resource, where Central has a material position in highly prospective acreage.
The Amadeus Basin contains several large, potentially multi-Tcf sub-salt targets that are also prospective for helium and hydrogen.
The return of Central’s interests in several sub-salt permits from a defaulting party last year are in the final government approval stages
which we expect to be completed shortly. Renewed sub-salt exploration at the Jacko Bore (Mt Kitty), Mahler (Magee) and Dukas prospects
has been progressing, with farmout discussions at an advanced stage.
Jacko Bore 2 (EP125)
Central 30%; Santos 70% (Operator)
Farmout discussions are progressing to secure part funding for an appraisal well, to be drilled within 12 months. 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 gas containing 11.5% hydrogen and 9% helium at up to 530,000 scfd.
Dukas 2 (EP112)
Central 45%; Santos 55% (Operator)
The Dukas-1 exploration well was drilled in 2019 and suspended after it encountered hydrocarbon-bearing gas from an overpressured zone
close to the primary target, with traces of helium and hydrogen detected in mud gases. Central is progressing discussions to secure farmout
funding for a new well at Dukas which will target the same sub-salt Heavitree formation with a higher-capacity rig.
Mahler (EP82)
Central 60%; Santos 40% (Operator)
Central is progressing farmout discussions and hopes to secure funding for the proposed Mahler exploration well to 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.
Central estimates that its share of gas resources across the three prospects (prior to any farmout) are:
Helium*
5.4
51.3
1.3
Hydrogen*
6.6
65.3
1.1
Natural gas
11.7
333.9
6.0
*Volume expected to be recovered in association with contingent and prospective hydrocarbon resources stated in the table. While estimated in accordance
with the SPE PRMS guidelines, Hydrogen and Helium are not officially classified in this system.
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.
Zevon (EP 115)
Central – 100% interest
Regional geological play mapping has highlighted that EP 115 has the potential to be highly prospective for helium and hydrogen in
association with hydrocarbon gasses.
A 2D seismic test line was acquired at Zevon in November 2023, confirming that the new acquisition methodology returned high quality
data with reduced environmental impact and significantly reduced cost. This bodes well for future seismic campaigns throughout EP115
and the wider Amadeus Basin. Based on the results of this test line, Central is updating its plans to acquire additional seismic in the licence
to further delineate a number of leads and prospects that have been identified in the block.
Additional resources guidance
The resources for the Dukas, Jacko Bore and Mahler prospects were first reported to ASX on 18 April 2023 and have been adjusted for Central’s
increased beneficial interests (Jacko Bore was 24%, now 30%), (Dukas was 35%, now 45%) and (Mahler was 29%, now 60%).
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.
Palm Valley (OL3); Dingo (L7); Mereenie (OL4/OL5), Amadeus Basin, Northern Territory
Central’s producing fields at Mereenie, Palm Valley and Dingo comprise several stacked layers of producing and potential oil and gas
reservoirs. There are opportunities to target intervals which are not currently the principal production zones in each field. If successful,
production wells could be tied into existing facilities relatively quickly and efficiently.
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 the Mamlambo oil prospect.
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 appraisal well could target the Lower Stairway Sandstone and the Pacoota Formation, both
of which are proven reservoirs in the Surprise and Mereenie fields. Total depth for a potential well would be in the order of 1,300m.
In-field and other opportunities
Dingo Deep
PJ
24.5
34.5
—
Palm Valley Deep
PJ
37.5
61.5
—
Mereenie Stairway
PJ
—
—
27.0
Orange
PJ
284.0
401.0
—
Total gas resource
PJ
346.0
497.0
27.0
Mamlambo (oil)
mmbbl
13.0
18.0
—
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 101)
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.
There are opportunities to target other intervals at Mereenie, Palm Valley and Dingo which are not currently the principal production
zones in each field.
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.
Northern Territory gas markets experienced considerable volatility during the year, with the Northern Gas Pipeline (NGP), which allows the
supply of gas from the Northern Territory to eastern states, being closed for much of the past 12 months due to supply-side interruptions.
At these times there was insufficient surplus gas in the Northern Territory to meet the NGP’s minimum volumes and Central was therefore
unable to supply gas to its customers in the Mt Isa region or access east coast spot markets while the pipeline was off-line. The NGP is
expected to remain closed until at least late 2024 when a new Blacktip field appraisal well is expected to be drilled offshore Darwin.
The interruptions impacted Central’s sales volumes by approximately 10%, or $4 million in revenue for the financial year. A new short-term
as-available gas sales agreement (GSA) with the Northern Territory’s Power and Water Corporation (PWC) has allowed Central to largely
mitigate the impact of the pipeline closure from April. For the second half of 2024, Central’s gas fields at Mereenie, Palm Valley and Dingo
are expected to supply around half of the Northern Territory’s daily gas requirements, with the remainder coming from offshore gas fields
such as Blacktip and Bayu Undan.
It was in the context of this transportation and supply-side market uncertainty that Central undertook a series of targeted marketing
initiatives during the year, including an extensive gas sale expression of interest process, which successfully concluded with new GSAs with
the NT Government that have strengthened and largely de-risked Central’s forward revenues through to the end of the decade.
The pricing for Central’s contracted gas portfolio from 2025 reflects strong market demand for firm gas supply on a term basis, with
minimal transportation costs. Central’s average portfolio contracted gas price from 2025 is expected to step-up from the $7.90 / GJe
realised in the June 2024 quarter.
As-available contract for 2024
In April, Central entered into an as-available supply
agreement with PWC in the Northern Territory for the
supply of up to 2.1 PJ of gas (Central’s share) until the end
of 2024. This agreement provides Central with a market
for gas that it could not otherwise deliver to its customers
in the Mt Isa region due to the suspension of the NGP.
South 32 in 2025
The existing two-year gas supply agreement with South32
Cannington Pty Ltd was extended by a further 12 months.
An additional 1.46 PJ of gas will be supplied to South32 at
Mount Isa in 2025 (Central share: 0.36 PJ).
Northern Territory Government (NTG) contracts from
2025
Central entered into new GSAs for the supply of up to 12.0 PJ of gas (Central share) to NTG for six years from 2025. The GSAs are structured
as a base load gas supply providing a high degree of certainty in Central’s forward gas revenues, regardless of the operating status of the
NGP over the foreseeable future. The contracts include:
the supply of up to 1.5 PJ of gas from Mereenie in 2025 if the NGP is closed and Central is unable to deliver gas to its existing east
coast customers, further mitigating risks to cash flow from any ongoing NGP interruptions; and
up to 3.3 PJ of gas from two new proposed Mereenie wells over six years from 2025.
Arafura contract from 2028
Central secured a new conditional GSA to supply up to 4.1 PJ of gas (Central share) to Arafura’s Nolan’s rare earths project in the Northern
Territory over three years from 2028. The GSA is subject to Arafura’s board approving a final investment decision to proceed with the
project by 31 December 2024.
The new contracts will mean that Central’s expected long-term firm production is now fully contracted (subject to Arafura approvals) at
fixed prices (plus CPI) for the next six years, including up to 1.5 TJ/d (Central share) from two new wells to be drilled at Mereenie.
The new GSAs are expected to provide more reliable cash flows for Central from 1 January 2025, benefitting from higher average
contracted gas prices and more consistent, firm sales that will not be affected by NGP interruptions. This increased cash flow certainty
is expected to underwrite new investments to increase production, support debt extension initiatives and accelerate returns to
shareholders.
Central Petroleum is committed to maintaining the highest environmental, social and governance standards across its operations.
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. As custodians of the land on which we operate, we aim to uphold the highest environmental standards and leave the smallest
footprint.
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.
We have had several visits and inspections during the year by regulatory agencies to monitor environmental conditions associated with our
operations. 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.
There were no reportable environmental incidents during the year at any Central operated fields. Climate change and emissions
Central recognises that climate change is a 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 is contributing 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.
At present, approximately half of the Northern Territory’s gas supply comes from
Central’s gas fields, with residents and businesses of Alice Springs relying 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 rely on our gas to supply rare minerals to worldwide
markets.
We report our greenhouse emissions under the National Greenhouse and Energy Reporting Act 2007 (NGER). In the most recent completed
reporting period, FY2023, our share of scope 1 and 2 emissions across our operations was consistent with the previous year, at 21,685 tons
of CO2e (21,612 tons in FY2022). On a per unit basis, our emissions intensity increased from 3.90 kgCO2e/GJe in FY2022 to 4.48 KgCO2e/GJe
in FY2023 due to increased flaring at the Range CSG gas project and increased gas volumes at Palm Valley.
We have invested in several initiatives to reduce our emissions, including the $8 million flare gas compressor at Mereenie, which was
commissioned this year and is expected to reduce flare gas emissions at Mereenie by more than 33% 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.
• We put safety first.
• We respect the environment and the communities we work with.
• We value our people and stakeholders.
•
Approximately 50% of the Northern
Territory’s gas supply comes from our
gas fields.
•
Supplied across the Northern Territory
for residents, manufacturers and
electricity generation.
•
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 rely on our gas to supply rare
minerals to worldwide markets.
At Central, the safety of our employees, contractors and the community are paramount. 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.
During the year, over 220,133 hours were worked, with no recordable injuries, resulting in a zero Total Recordable Injury Frequency Rate
(TRIFR) at 30 June 2024.
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:
•
35% of our staff live locally.
•
23% of our on-site staff are indigenous.
•
Central and partners paid over $8.0 million in royalties to the Northern Territory and Central Land Council for FY2024.
•
Central and partners spent over $1.8 million with local contractors and businesses and incurred over $1.9 million in fees and levies
to the Northern Territory government, in FY2024.
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 Northern Territory 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 73.3 PJe at 30 June 2024.
Oil
Proved reserves (1P)
mmbbl
0.34
(0.03)
—
(0.01)
0.30
0.28
0.01
Proved plus probable
reserves (2P)
mmbbl
0.38
(0.03)
—
0.01
0.36
0.34
0.02
Contingent Resources (2C)
mmbbl
0.05
—
—
—
0.05
—
—
Gas
Proved reserves (1P)
PJ
60.76
(3.69)
0.56
57.62
45.21
12.41
Proved plus probable
reserves (2P)
PJ
72.83
(3.69)
2.03
71.17
54.93
16.24
Contingent Resources (2C)
PJ
185.21
—
(135.05)
8.44
58.60
—
—
1 All developed and undeveloped 1P and 2P reserves are located in the Amadeus Basin geographical area.
Mereenie, oil
Proved reserves (1P)
mmbbl
0.34
(0.03)
—
(0.01)
0.30
Proved plus probable reserves (2P)
mmbbl
0.38
(0.03)
—
0.01
0.36
Contingent Resources (2C)
mmbbl
0.05
—
—
—
0.05
Mereenie, gas
Proved reserves (1P)
PJ
28.73
(1.35)
—
0.68
28.06
Proved plus probable reserves (2P)
PJ
37.48
(1.35)
—
0.50
36.64
Contingent Resources (2C)
PJ
45.60
—
—
—
45.60
Palm Valley
Proved reserves (1P)
PJ
12.61
(1.64)
—
(0.07)
10.90
Proved plus probable reserves (2P)
PJ
13.41
(1.64)
—
(0.09)
11.69
Contingent Resources (2C)
PJ
4.56
—
—
1.94
6.50
Dingo
Proved reserves (1P)
PJ
19.42
(0.71)
—
(0.05)
18.66
Proved plus probable reserves (2P)
PJ
21.94
(0.71)
—
1.62
22.84
Range (Surat Basin, Qld)
Contingent Resources (2C)
PJ
135.05
—
(135.05)
—
—
Note: Estimates may not arithmetically balance due to rounding.
The information contained in this Reserves and Resources Statement is based on, and fairly represents, information and supporting
documentation prepared by, or under the supervision of Mr. John Hattner who is a full-time employee of Netherland, Sewell & Associates,
Inc. (“NSAI”) where he holds the position of Senior Vice President. Mr. Hattner is a member in good standing of the Society of Petroleum
Engineers, is qualified in accordance with ASX listing rule 5.41. and has consented to the inclusion of this information in the form and
context in which it appears.
Central 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 the 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 includes 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
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 and
regulatory requirements.
Failure to comply may impact
our license to operate.
Stakeholders have evolving
expectations of social
responsibility and ethical
decision making, which
exceed regulatory
requirements.
Failure to meet stakeholder expectations can
lead to opposition and a decline in support for
both our operational activities and future
growth opportunities.
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.
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.
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.
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.
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
and look for joint venture partners to assist with
funding and sharing of risk.
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 capital projects.
We utilise an established project management
framework which is supported by skilled and
experienced personnel to govern and deliver major
projects.
Oil and Gas Reserves
Commercialisation of
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.
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.
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 has locked-in sales for estimated firm
forward production until 2030 at fixed pricing on a
take-or-pay basis.
Central has opportunities to diversify its reliance on
hydrocarbons by targeting valuable non-
hydrocarbon gases such as helium and naturally
occurring hydrogen which potentially exist in some
of its production and exploration permits.
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.
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.
Our interactions with, and decisions involving
landholders, traditional owners, suppliers and
the community fails to attract and maintain the
continued support of the communities in which
we operate.
We work in conjunction with our key stakeholders
and have established programs to support and assist
the communities in which we operate through
donations, sponsorships, local procurement, training
and providing ongoing local employment and
business opportunities.
Health and Safety
Health and Safety is at the
heart of all activities and
decisions at Central.
Health and Safety incidents or accidents may
adversely impact our people, the communities
in which we operate, our reputation and/or
our licence to operate.
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 have in place robust, safe
systems of work, and an effective health and safety
management system.
People and Culture
We must have the right
capability and capacity within
our business through
personnel who are engaged
and enabled to deliver our
current business and future
growth opportunities.
Failure to establish and develop sufficient
capability and capacity to support our
operations may impact achievement of our
objectives.
We are focussed on securing and developing the
right people to support the operation and
development of our portfolio of assets and
opportunities. We also proactively engage
contractors to supplement any short-term gaps in
capability and capacity to support the execution of
our business plans.
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.
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.
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.
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.
Joint Ventures
Although we operate most of
the tenements we hold, we
are dependent on technical
and commercial alignment
with our joint venture
partners.
Misalignment between joint venture partners,
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.
We work closely with our new and existing joint
venture partners to achieve mutually beneficial
outcomes.
Access to Infrastructure
Our financial performance
and growth strategy are
dependent on access to third
party owned infrastructure.
Negative impacts to revenue as a result of
infrastructure failure or closure, increased
tariffs, or restricted access to third party
owned infrastructure.
Over the past year Central has been exposed to
multiple outages which has restricted our
access to east coast gas markets.
We seek to work closely with customers and
suppliers of infrastructure to mitigate the risk of
closure or failure, however we have little or no
control over the outcome. We continue to explore
alternative routes to market to diversify risk where
possible.
Central has locked-in sales for estimated firm
forward production until 2030 at fixed pricing on a
take-or-pay basis within the NT, mitigating exposure
to interruptions to the NGP.
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.
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.
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.
Oil revenue represented less than 10% of
consolidated sales revenue in FY2024.
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 as its level of production
falls below eligibility thresholds and its gas supplies
are only to domestic markets.
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.
Failure to safeguard the confidentiality,
integrity, availability and reliability of digital
data and intellectual property.
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.
Digital risks are identified, assessed and managed
based on the business criticality of our systems,
which may be segregated and isolated if required.
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.
Geographic Concentration
We face risks associated with
the concentration of our
production assets.
Central’s revenue is derived from oil and gas
production in the Amadeus Basin leaving
Central exposed to downsides associated with
weather conditions and infrastructure failure.
We ensure that appropriate insurance is in place to
mitigate the impact of any extended business
interruption. We are also investigating other new
ventures outside of the Amadeus Basin.
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 2024.
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 Stephen Gardiner
Mr Troy Harry (resigned 5 February 2024)
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 (2023: $Nil). No recommendation for payment of dividends has been made.
The operating and financial highlights for the financial year were:
•
Central sold its 50% interest in the Range CSG Project (ATP2031) for $12.5 million, releasing capital and realising a book profit of
$13.8 million.
•
Gas which was pre-sold in 2020 was fully delivered by December 2023, releasing additional gas volumes for sale on usual cash
terms and boosting cash flows from January 2024 onwards.
•
New gas sales agreements (GSAs) were secured including:
-
An as available GSA with Power & Water Corporation in the NT for the supply of up to 2.1 PJ (Central share) until the end of
2024;
-
New GSAs for the firm base supply of up to 12 PJ (Central share) of gas to the Northern Territory Government for six years
from 2025 to 2030; and
-
A revised GSA for the supply of up to 4.1 PJ of gas to Arafura’s Nolan’s rare earth project over three years from 2028,
subject to project FID by 31 December 2024.
•
In August 2023, agreement was reached to progress 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 2024, including principal risks is provided on pages
3 to 21 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 2024:
•
Central sold its 50% interest in the Range CSG Project (ATP2031), releasing capital and realising a book profit of $13.8 million.
•
Interruptions to the Northern Gas Pipeline impacted sales during the year.
•
New gas sale agreements were secured and are expected to provide more reliable cash flows for Central, largely mitigating
exposure to the Northern Gas Pipeline.
•
Agreement was reached to progress a helium recovery and liquefaction unit at Mereenie. Work continues with parties that
include a major helium distributor.
There were no other significant events that are not detailed elsewhere in this Annual Report.
In July 2024, new Gas Sale Agreements were executed and are expected to provide more reliable cash flows for Central from 1 January
2025, benefitting from higher average contracted gas prices and more consistent, firm sales that will not be affected by interruptions to the
Northern Gas Pipeline.
No other significant matters or circumstances have arisen between 30 June 2024 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.
Commercial
Demand for gas is expected to remain strong through FY2025, with new gas sale agreements expected to provide more reliable cash flows,
benefiting from higher average contracted gas prices and more consistent firm sales that will not be affected by pipeline interruptions
Production enhancement
Two new development wells are expected to be drilled at Mereenie in the first half of 2025 to boost production capacity for supply into
new gas sale agreements. Planning has also commenced for two new wells at Palm Valley.
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 is dependent on finalising
farmout arrangements.
Other proposed near-term exploration activity includes seismic acquisition in EP115, which hosts the large Zevon lead, to identify a possible
site for an exploration well.
Helium Recovery Unit
Central and its partners at Mereenie are working with a major global helium supplier to progress towards a final investment decision for
the construction of a helium recovery and liquefaction unit at Mereenie. 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.
Further information on these activities is included from pages 1 to 21 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 40 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, electricity transmission, gas
processing, LNG and underground storage.
Mr McCormack is a former Managing Director and CEO of APA Group (2004-2019), former Non-executive Director of
Austal Limited (2020 – 2024) and former Director of Envestra (now Australian Gas Infrastructure Group) and the
Australian Pipeline Industry Association (now Australian Pipelines and Gas Association). He is a Non-executive Director
at Origin Energy Limited and Whitehaven Coal Limited, a Director of the Clontarf Foundation and is Chair of the
Australian Brandenburg Orchestra Foundation and is the Patron of the Australian Ice Hockey League. He is also a Fellow
of the Australian Institute of Company Directors.
Directorships of other listed companies in the last three years: Director of Origin Energy Limited, Director of
Whitehaven Coal Limited from February 2024, and Austal Limited to March 2024.
Managing Director and Chief Executive Officer
Mr Devaney has over 25 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 identifying and 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, which was recently sold for a book profit
of $13.8 million. 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.
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 Sims Limited and Chief Executive Women.
Ms Hirschfeld has also been a board member and President of UN Women National Committee Australia and non-
executive director of Spark Infrastructure RE Limited, 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 Fellow of the Australian
Institute of Company Directors and the Academy of Engineering and Technology.
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), President of the Chamber of
Commerce and Industry WA and Non-Executive Director of Oil Search Limited and Suvo Strategic Minerals Ltd.
Directorships of other listed companies in the last three years: Director of Suvo Strategic Minerals Ltd from
5 September 2023 until 13 June 2024.
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:
Leon Devaney
9
9
—
—
5
—
8
—
13
Stephen Gardiner
9
9
4
4
5
5
8
8
15
14
Troy Harry3
5
5
2
2
—
2
4
4
15
15
Katherine Hirschfeld AM
9
8
4
4
5
5
—
7
15
13
Agu Kantsler
9
7
—
4
5
4
8
7
15
13
Michael McCormack
9
9
4
4
5
5
8
8
15
13
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 Troy Harry resigned as Director on 5 February 2024.
(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
15,300
14,280
Other tax related services
21,581
47,512
Total remuneration from non-audit services
36,881
61,792
Dear Shareholders,
The Board continued to focus on finding the right remuneration
balance to retain and attract high-quality staff, while also providing
appropriate performance incentives that are aligned with shareholder
expectations. However we acknowledge that the 2023 Remuneration
Report failed to get the support of 75% of eligible shareholders who
voted at Central’s 2023 Annual General Meeting.
We have responded by making significant changes to the remuneration
structure of our executive team for FY2025 and beyond to further align
the performance of management and staff with the interests of
shareholders.
The CEO’s remuneration package has been re-weighted with a reduced
fixed remuneration and new at-risk incentives with much higher share
price appreciation hurdles. The pay of other executives has been frozen
at 2024 level, and we have consolidated our executive team to four,
down from the six executives that Central has historically employed.
The revised short and long-term incentives now include an equity-
linked plan that only rewards significant increases above a minimum
hurdle share price of 8 cents per share (a minimum 50% increase on
the 5.3 cents share price at 30 June 2024).
I’ve no doubt the Company’s struggling share price had a large part to
play in the shareholder vote last year. However, the results and
accomplishments over the past year have driven significant
improvements in our forecasted free cash flows and future shareholder
returns. The sale of the Range gas project at a significant profit has
strengthened our balance sheet; our pre-sold gas has been fully
returned, increasing our gas sales in a stronger market; and our new
six-year, higher-priced firm gas contracts provide a new level of
financial capacity.
Our staff did a commendable job in maintaining a reliable supply of gas
to our customers in the face of variable demand, and did so with a
clean safety record for the year. Management has negotiated the
pipeline-driven challenges which threatened current and future
revenues and cash flows, redirecting gas into an alternative contract in
the Northern Territory for the remainder of this year. The recently
announced six-year contracts for gas supply to the Northern Territory
Government, stretching from next year until 2030, will mitigate market
and transportation risks and provide energy security for the region.
To maintain our capability and incentivise exceptional future
performance, Central’s new FY2025 executive incentive plan offers a
remuneration structure that addresses shareholder expectations for
share price appreciation.
Fixed remuneration
To maintain competitiveness in the labour market and counteract the
effects of rising costs of living for our staff, fixed remuneration rose by
an average 4% across the board for FY2024, plus the required 0.5%
increase in the superannuation guarantee. A similar increase has been
applied for the 2025 financial year, except for the CEO, whose fixed
remuneration has decreased by 13% and executives whose pay has
been frozen at FY2024 levels, the second time in five years that
executive pay has been frozen.
I also note there has been no increase in Directors’ Fees for the last six
years.
Short-term incentives
Depending on role and seniority, the maximum FY2024 opportunity
ranges from 10% to 30% of fixed remuneration.
The short-term incentive awarded for FY2024 was impacted by the
lower production volumes and delays to various commercial,
development and farmout initiatives, resulting in an award to staff
(other than executives) of 54% of the maximum available, including
measurement against personal KPIs.
A small number of select key operational staff also received a retention
incentive which was offered to maintain operational capability during
the strategic review process which was completed this year.
Executive incentives
For FY2024, executives participated in the third and final year of the
Executive Incentive Plan (EIP) with short and long-term components.
The EIP provided for the CEO the ability to receive up to a maximum of
120% of fixed remuneration and 80% for other eligible executives.
Of the maximum available, 51% was awarded, based on the same
corporate KPIs as the short-term incentives for other staff, but without
a personal KPI component. One third has been paid as cash and two
thirds will be granted as equity which can vest over the next three
years.
The Board has acknowledged feedback from shareholders and
undertaken an independent benchmarking review of executive
incentive plans, resulting in a revised incentive plan for executives for
FY2025.
The annual short-term component provides the CEO with the ability to
earn up to circa 63% of his now reduced fixed remuneration upon
achieving stretch corporate performance targets each year. Other
eligible executives can earn up to circa 42% of their fixed remuneration.
Upon determination of the achieved reward at the end of FY2025, 80%
will be paid as cash and 20% as share rights which vest a year later.
The long-term component is based entirely on the absolute
appreciation of share price rather than including any relative peer
group share price appreciation component. This is designed to directly
align management and shareholders, comprising of share rights whose
vesting requires the achievement of fixed share price appreciation
targets over three years.
The new long-term plan only provides a reward where the share price
increases to at least 8 cents per share in three years (an increase of
about 50% from the 30 June share price of 5.3 cents per share). At that
threshold level, the CEO would earn a long-term incentive of 50% of his
reduced FY2025 fixed remuneration (15% for other executives),
increasing to 218% of fixed remuneration if the share price reaches 16
cents, more than triple today’s price (65% for other executives). In
addition, the number of shares awarded under the long-term incentive
plan is based on pricing at the time of vesting such that executives
don’t benefit from the current low share price.
We believe that the much more conservative remuneration and
incentive arrangements for FY2025 provide the appropriate balance of
incentive to retain and attract quality staff and drive longer term share
price appreciation that will ultimately benefit all shareholders.
Michael (Mick) McCormack
Remuneration and Nominations Committee Chair
This Remuneration Report for the year ended 30 June 2024 (FY2024) 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
Directors and Key Management Personnel (KMP)
B
Remuneration Overview
C
Remuneration Policy
D
Remuneration Consultants
E
Long Term Incentive Plan – Employee Rights Plan (LTIP)
F
Executive Incentive Plan (EIP)
G
Short Term Incentive Plan (STIP)
H
Key operational employee retention incentive
I
FY2025 Executive Incentive Plan (FY25 EIP)
J
Realised Remuneration
K
Remuneration Details – Statutory Tables
L
Executive Service Agreements
M
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
Independent Non-executive Chair
Mr Leon Devaney
Managing Director and Chief Executive Officer
Mr Stephen Gardiner
Independent Non-executive Director
Mr Troy Harry
Non-executive Director (resigned 5 February 2024)
Ms Katherine Hirschfeld AM
Independent Non-executive Director
Dr Agu Kantsler
Independent Non-executive Director
Mr Ross Evans
Chief Operations Officer
Mr Damian Galvin
Chief Financial Officer
Mr Daniel White
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:
a.
Linking internal strategies to improved shareholder value through achievement of appropriate KPIs.
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.
Fixed remuneration
An average 4% pay rise applied to eligible employees for FY2024 and compulsory superannuation
contributions increased from 10.5% to 11%.
Executive Incentive Plan
(EIP)
Achievement of Group-wide corporate KPIs resulted in an award of 51% 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 F of this report.
Short Term Incentive Plan
(STIP)
Achievement of Group-wide corporate and individual KPIs resulted in payment of an average 54% of the
maximum STIP to eligible employees. Refer Section H of this report.
Key operational employee
retention incentive
A select group including an executive and key operational employees earned a retention incentive equal to
15% of their fixed remuneration in connection with the strategic review first announced in August 2022 and
completed in FY2024.
Vesting of Share Rights
previously granted under
the Long Term Incentive
Plan (LTIP)
The Share Rights issued to participating employees under the Long Term Incentive Plan ($1,000 Exempt
Plan) for the three year period ending 30 June 2024 fully vested on 30 June 2024 for those employees
meeting the relevant service requirements. Refer Section E of this report.
At the Company’s 2023 Annual General Meeting, 47.31% of the votes cast were against the adoption of the FY2023 Remuneration Report.
In response to this vote by eligible shareholders, the Board has conducted a review of remuneration of executives and taken the following
action:
a.
Amended the Managing Director / CEO’s remuneration arrangements, resulting in a 13% decrease in total fixed remuneration;
b.
Frozen total fixed remuneration at FY2024 levels for Directors and other Key Management Personnel for FY2025;
c.
Implemented a revised incentive plan for FY2025, which includes share price performance hurdles for the Managing Director /
CEO and other Key Management Personnel (refer Section I of this report);
d.
Held the number of KMPs at four, down from six two years ago; and
e.
Retained a smaller Board of four Non-executive Directors, down from five at the start of the year.
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 have participated in an Executive Incentive Plan (EIP) that combined both short term annual KPIs and a longer-
term, deferred equity-based component (refer Section F of this report). For FY2025, it is proposed that executives participate in a revised
EIP which includes both short-term annual KPIs which have a deferred equity component and a longer term component linked to share
price performance over three years (refer Section I of this report).
Other personnel participate in a Short Term Incentive Plan (STIP), which provides an incentive linked to achievement of corporate and
personal KPIs (Section G), and are also eligible for an annual grant of equities to a value of $1,000 with a three year vesting period (refer
Section E of this report).
For periods up to and ending on 30 June 2024, the remuneration of directors and executives consisted of the following key elements:
Following a market review of comparable companies, the Managing Director and CEO’s fixed remuneration has been reduced from 1
July 2024, and other executives’ fixed remuneration has been frozen at FY2024 levels.
As at 1 July 2024, salaries for other eligible employees will rise, on average, by 4% for FY2025, with an added benefit from the statutory
increase in compulsory superannuation contributions from 11% to 11.5%.
Non-executive directors:
1.
Fees including statutory superannuation;
2.
Up to 25% sacrifice of FY2024 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 FY2024.
The balance of fixed and maximum at risk remuneration for executives for FY2024 is summarised as follows:
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 performance1
Operating revenue
$ million
65.0
59.8
42.2
39.3
37.2
Profit/(loss) after income tax
$ million
5.4
0.2
21.3
(8.0)
12.4
Underlying EBITDAX2
$ million
25.0
26.1
16.8
15.8
13.8
Net cash/(debt)
$ million
(46.1)
(31.3)
(10.2)
(14.3)
0.8
Shareholder wealth
Share price at year end
$/share
$0.081
$0.117
$0.110
$0.053
$0.053
Absolute TSR (3 years)
% growth pa
(16.1%)
(9.1%)
(4.6%)
(13.1%)
N/a
Relative TSR (3 years)
Percentile rank
25th
57th
69th
56th
N/a
Incentive awarded
STIP
% of maximum
67.0%
67.0%
62.75%
51.0%
54.0%
LTIP
% of maximum
nil
31.5%
43%
29.9%
N/a
EIP
% of maximum
N/a
N/a
62.5%
45.0%
51.0%
1 Central sold a 50% interest in its producing gas fields on 31 October 2021.
2 Underlying EBITDAX is underlying Earnings before Interest, Tax, Depreciation, Amortisation, Impairment and Exploration costs and profit on disposal of
interests in producing properties and exploration permits. Refer to the Operating and Financial Review for further information.
The expansion programs at the Group’s Amadeus Basin oil and gas fields, funded by debt, gas presales and gas overlifts enabled increased
production into new markets upon the opening of the Northern Gas Pipeline in early 2019, resulting in strong revenues and EBITDAX. The
STIP awards in FY2020 and FY2021 reflected these results and were paid as a combination of cash, equity and deferred equity over those
years. 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 and EIP awards were lower in FY2023 and FY2024, with a relatively strong operating performance from the smaller asset base offset
by slow progress on commercial initiatives and delays and cost overruns to the Company’s exploration and development programs.
Share price performance was not relevant for the LTIP vesting during FY2024 following changes to the LTIP (which is now limited to the
$1,000 Exempt Plan with no share price performance hurdles), and the establishment of the EIP from FY2022. The LTIP awards over prior
years followed the Group’s 3 year share price performance. 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 saw a
decline in share price in absolute terms, but Central’s shares performed relatively well against those of its peers, resulting in a partial
vesting of LTIPs for participants in those years.
No remuneration consultants were engaged to provide remuneration recommendations in relation to the remuneration of any Key
Management Personnel for FY2024.
Guerdon Associates were engaged to provide market information relating to a revised short and long term incentive strategy for FY2025,
and provided market information from peer companies relating to fixed and variable remuneration for Key Management Personnel for
FY2025.
The final three year performance period for performance-linked LTIP plans ended on 30 June 2023. These plans vested in August of 2023 at
the vesting rate of 29.935% following final approval of the board.
All eligible employees may now participate in the Central Petroleum $1,000 Exempt Plan (other than key management personnel) which
operates to align the interests of employees and shareholders by providing employees with opportunity to earn equity in the Company
over a three year period.
No performance conditions apply, other than continuing employment with the Company at the end of a three-year service period.
Participation
In 2021, Central established an EIP for key executives to align executive performance with the achievement of key objectives for FY2022,
FY2023 and FY2024. The Executive Incentive Plan has been revised for FY2025, with details outlined at Section I of this report.
Key terms and vesting conditions
The EIP is an integrated incentive with both short term and long-term components. The value of the EIP award is determined at the end of
the 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.
FY2024 Performance
After assessment of the achievement of the Corporate KPIs (refer Section G of this report) and the Company’s performance during the
year, eligible executives were entitled to receive, on average, 51% of their maximum EIP bonus. Of this award, 33% was paid in August
2024, 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 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
30 %
2
20 %
3
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:
a)
Role and responsibilities;
b)
Involvement in strategic and operational aspects of management;
c)
Ability to be a key driver of the operational parts of the Group’s business; and
d)
Ability to influence the Group’s performance.
The CEO and executives who participate in the EIP are not eligible to participate in the STIP (refer Section F of this report).
At the Board’s discretion the STIP award may be paid through a combination of cash and/or Company securities.
FY2024 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, 54% of their maximum STIP bonus. The STIP bonuses were paid in August 2024.
The Financial Year 2024 STIP (FY2024 STIP) was designed to recognise and reward individual effort by connecting individual KPIs and
corporate KPIs and was assessed across three categories:
Corporate KPIs
60 %
31 %
51% satisfaction of corporate KPIs
Individual KPIs
40 %
23 % (avg)
57.5% satisfaction of individual KPIs
100 %
54 % (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 FY2024 STIP, depending on their participation level.
Corporate KPIs for FY2024:
Production (gas – sales volume)
Assessed against budget
17%
Total Cost1
Total group operating and capital expenditure for agreed
scope of works assessed against budget
17%
Growth & Development Milestones
Assessed against budget, commercial viability and
schedule
15%
Farmout
Assessed against the number of binding agreements
15%
Subsalt
Restructure Joint Ventures and permits
15%
Traditional Owner cultural heritage
Assessed against compliance with agreements
3%
Safety
Total Recordable Incident Frequency Rate (TRIFR)
5%
Process Safety
Unplanned or uncontrolled release of materials from a
process (loss of primary containment – LOPC)
5%
Environment Recordable environmental incidents
5%
NT Operations (maintain Indigenous employment)
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 FY2024 were assessed as achieving an average of
57.5% (or a weighted average of 23% out of a maximum possible 40%).
Participation
For the Chief Operating Officer and a small number of other selected operational employees, a retention incentive was implemented as
part of the retention strategy made in connection with the Strategic Review announced in August 2022.
Key terms and vesting conditions
The retention incentive was a cash payment equal to 15% of the participants’ Total Fixed Remuneration (TFR). The retention incentive was
conditional upon the participant remaining employed by the Group in the period up to when the payment was due, being as soon as
possible after the earlier of completion of a transaction resulting from the Strategic Review and 30 June 2024. The bonus was paid to
eligible employees in August 2024.
Following a review of the Company’s executive incentive plans, Central will establish a new EIP for key executives to align performance
with the achievement of key objectives and share price hurdles for the FY2025 Plan Year.
The FY25 EIP is made up of two components consisting of a:
a)
short-term incentive based on achieving annual KPIs, with both cash and deferred equity components; and
b)
long term incentive, with share-price based performance hurdles over a three year performance period.
FY25 EIP Short Term Incentive
The value of the short-term incentive award is determined annually at the end of a one year performance period upon measurement of
performance against Board established KPI targets for that year. The Short Term Incentive award is split into two parts:
a)
80% is paid at the end of the one year performance period; and
b)
The 20% balance of the awarded value is granted as Service Rights that vest at the end of the year following the initial one year
performance period (Retention Period).
The Short Term Incentive’s maximum opportunity for the executive team as a percentage of Total Fixed Remuneration (TFR) is:
CEO: 50% at Target (maximum stretch achievement at 62.5% of TFR);
Other eligible executives: 33.33% at Target (maximum Stretch achievement at 41.67% of TFR).
The number of Service Rights awarded under the Short Term Incentive is determined by reference to Central’s volume weighted average
share price over the 20-trading days ending on 30 June at the end of the performance period.
The Service Rights are the right to acquire fully paid ordinary shares for no exercise price at the end of the Retention Period and can be
exercised from the completion of the Retention Period to the Expiry Date (five years from the beginning of the Retention Period). 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 calculated on the basis of the dividends or return of capital that would have been
paid in respect of the Share being reinvested over the Retention Period to exercise.
Service Rights do not automatically vest on change of control, but vest as a function of the service period and the circumstances of the
change in control, subject to discretion of the Board.
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 some, none, or all the Service Rights, having regard for the prevailing facts and circumstances at the time of cessation.
The FY25 Long Term Incentive
As a long term incentive, from FY2025 eligible executives will be granted Performance Rights that vest if the Company’s share price exceeds
specified Share Price Hurdles at the end of a three year performance period. The number of Rights available under the long-term incentive
plan are based on pricing at the time of vesting such that executives don’t benefit from the current low share price conditions.
For the FY2025 plan year, the Performance Rights will be subject to achieving a minimum Share Price Hurdle of $0.08 per share over a
three year period, requiring a 51% increase from Central’s share price at 30 June 2024. At this share price, approximately 46% of the
Performance Rights will vest, increasing to a maximum of 100% if the share price reaches $0.16, more than triple the Company’s 2024
share price. The value of the long term incentive, relative to TFR at the relevant Hurdle Share Price is set out below:
The Performance Rights will only vest if the Share Price Hurdles are achieved and vesting is subject to the executive’s on-going employment
with the Company in accordance with the Plan Rules and the Share Rights Offer. Upon cessation of employment, the Performance Rights
remain on foot to be tested in the normal course, with the Board having the discretion to forfeit some, none or all of the Performance
Rights, having regard for the prevailing facts and circumstances at the time of cessation.
The $0.08 Share Price Hurdle is a binary, all-or nothing minimum hurdle at which 46% of Performance Rights will vest. The remaining 54%
of Performance Rights will vest pro-rata on a straight-line basis between the $0.08 and $0.16 Share Price Hurdles. Vested Performance
Rights may be exercised in accordance with the Employee Rights Plan Rules. The Board may convert vested Share Rights into either Shares
or cash or a combination thereof. The number of Performance Rights which vest at the end of the Performance Period is determined by
reference to Central’s volume weighted average share price over the 20-trading days ending on 30 June 2027.
The Performance Rights are the right to acquire fully paid ordinary shares for no exercise price at the end of the Performance Period and
can be exercised up to five years from the commencement of the Performance Period. To maintain alignment with shareholders, the
Performance Rights have a dividend and return of capital entitlement whereby the Performance Rights convert to one share plus an
additional number of shares calculated on the basis of the dividends or return of capital that would have been paid in respect of the Share
being reinvested from the commencement of the Performance Period to exercise.
Performance Rights do not automatically vest on change of control, but vest as a function of the service period and the circumstances of
the change in control, subject to discretion of the Board.
Table 1 identifies the actual remuneration received by Senior Executives in respect of the 2024 financial year. Realised Remuneration
reflects the pre-tax 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; and
The value of EIP and LTIP share rights vesting (if any) in respect of the three-year period ending 30 June, valued at the year-end
share price (2024: 5.3 cents per share, 2023: 5.3 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
2024
681,849
139,097
8,839
153,172
982,957
2023
654,572
117,823
8,192
55,833
836,420
Ross Evans6
2024
558,079
156,233
8,839
90,697
813,848
2023
535,557
64,267
8,192
30,447
638,463
Damian Galvin
2024
369,179
50,208
8,839
58,606
486,832
2023
353,926
42,471
8,192
20,108
424,697
Duncan Lockhart4
2024
—
—
—
—
—
2023
113,160
—
2,007
4,043
119,210
Jonathan Snape5
2024
—
—
—
—
—
2023
194,107
—
4,895
9,815
208,817
Daniel White
2024
495,639
67,407
8,839
78,782
650,667
2023
475,523
57,063
8,192
50,994
591,772
Total Executive KMP
2024
2,104,746
412,945
35,356
381,257
2,934,304
2023
2,326,845
281,624
39,670
171,240
2,819,379
1 Total Fixed Remuneration includes salaries, fees and superannuation contributions.
2 Includes car parking and other fringe benefits.
3 Shares comprise any shares to vest from the EIP or LTIP from prior years where the performance period ended on 30 June of the relevant year and are valued at that
date. Vesting will occur upon the issue of a vesting notice.
4 Duncan Lockhart resigned 31 August 2022.
5 Jonathan Snape resigned 20 January 2023.
6 Ross Evans’ STIP/EIP Includes a key operational employee retention incentive. Refer Section H above.
Non-Executive Directors
Stephen Gardiner
2024
72,500
—
—
7,975
—
—
19,309
99,784
—
2023
70,833
—
—
7,438
—
—
18,251
96,522
—
Katherine Hirschfeld
2024
85,000
—
—
9,350
—
—
—
94,350
—
2023
78,000
—
—
8,190
—
—
7,300
93,490
—
Agu Kantsler
2024
62,500
—
—
6,875
—
—
19,309
88,684
—
2023
62,500
—
—
6,563
—
—
18,251
87,314
—
Michael McCormack
2024
117,500
—
—
12,925
—
—
35,860
166,285
—
2023
117,500
—
—
12,338
—
—
33,895
163,733
—
Former Non-Executive Directors
Stuart Baker4
2024
—
—
—
—
—
—
—
—
—
2023
14,167
—
—
1,488
—
—
—
15,655
—
Troy Harry5
2024
47,816
—
—
5,260
—
—
—
53,076
—
2023
66,402
—
—
6,972
—
—
—
73,374
—
Sub-total
2024
385,316
—
—
42,385
—
—
74,478
502,179
—
2023
409,402
—
—
42,989
—
—
77,697
530,088
—
Executives
Leon Devaney
2024
679,448
139,097
8,839
27,399
—
12,600
216,083
1,083,466
33%
2023
640,142
117,823
8,192
25,292
—
22,307
177,683
991,439
30%
Ross Evans
2024
547,708
139,130
8,839
27,399
—
16,196
126,848
866,120
31%
2023
508,712
81,370
8,192
25,292
—
9,717
117,477
750,760
26%
Damian Galvin
2024
331,213
50,208
8,839
27,399
—
5,509
83,857
507,025
26%
2023
340,936
42,471
8,192
25,292
—
5,856
76,803
499,550
24%
Duncan Lockhart6
2024
—
—
—
—
—
—
—
—
—
2023
66,458
—
2,007
6,323
—
(15,824)
(43,061)
15,903
—
Jonathan Snape7
2024
—
—
—
—
—
—
—
—
—
2023
170,679
—
4,895
14,543
—
(2,706)
(21,944)
165,467
—
Daniel White
2024
471,549
67,407
8,839
27,399
—
9,253
112,638
697,085
26%
2023
469,673
57,063
8,192
25,292
—
18,425
135,958
714,603
27%
Sub-total
2024
2,029,918
395,842
35,356
109,596
—
43,558
539,426
3,153,696
30%
2023
2,196,600
298,727
39,670
122,034
—
37,775
442,916
3,137,722
24%
Total Remuneration
2024
2,415,234
395,842
35,356
151,981
—
43,558
613,904
3,655,875
28%
2023
2,606,002
298,727
39,670
165,023
—
37,775
520,613
3,667,810
22%
1 Includes movements in annual leave provisions.
2 Short term incentives are unpaid at the end of the financial year. Includes key operational employee retention incentive. Refer Section H above.
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 based upon the
service periods over which rights to shares will vest. 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 Stuart Baker resigned 30 August 2022.
5 Troy Harry was appointed 1 September 2022 and resigned 5 February 2024.
6 Duncan Lockhart resigned 31 August 2022.
7 Jonathan Snape resigned 20 January 2023.
Leon Devaney
2024
272,740
139,097
51.0%
49.0%
2023
261,829
117,823
45.0%
55.0%
Ross Evans1
2024
229,161
156,233
68.2%
31.8%
2023
142,815
64,267
45.0%
55.0%
Damian Galvin
2024
98,448
50,208
51.0%
49.0%
2023
94,380
42,471
45.0%
55.0%
Daniel White
2024
132,170
67,407
51.0%
49.0%
2023
126,806
57,063
45.0%
55.0%
Total
2024
732,519
412,945
56.4%
43.6%
2023
625,830
281,624
45.0%
55.0%
1 Ross Evans was entitled to a retention incentive of 15% of total fixed remuneration implemented as part of the retention strategy made in connection with the
Strategic Review announced in August 2022. The incentive was 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 $80,334 is included in the 2024
awarded incentives for this retention incentive.
Non-Executive Directors1,5
Stephen Gardiner
2024
386,182
14 Nov 23
0.050
—
30 Jun 28
2023
217,275
11 Nov 22
0.084
—
30 Jun 27
Katherine Hirschfeld
2024
—
—
—
—
—
2023
86,910
11 Nov 22
0.084
—
30 Jun 27
Agu Kantsler
2024
386,182
14 Nov 23
0.050
—
30 Jun 28
2023
217,275
11 Nov 22
0.084
—
30 Jun 27
Michael McCormack
2024
717,196
14 Nov 23
0.050
—
30 Jun 28
2023
403,511
11 Nov 22
0.084
—
30 Jun 27
Sub-total
2024
1,489,560
2023
924,971
Executives2
Leon Devaney5
2024
4,021,260
14 Nov 23
0.050
—
14 Nov 28
2023
3,160,353
10 Nov 22
0.083
—
10 Nov 27
Ross Evans
2024
2,193,405
14 Sep 23
0.053
—
14 Sep 28
2023
1,723,434
19 Sep 22
0.096
—
19 Sep 27
Damian Galvin
2024
1,449,525
14 Sep 23
0.053
—
14 Sep 28
2023
1,138,215
19 Sep 22
0.096
—
19 Sep 27
Duncan Lockhart3
2024
N/A
N/A
N/A
N/A
N/A
2023
76,283
19 Sep 22
0.096
—
19 Sep 27
Jonathan Snape4
2024
N/A
N/A
N/A
N/A
N/A
2023
1,111,113
19 Sep 22
0.096
—
19 Sep 27
Daniel White
2024
1,947,534
14 Sep 23
0.053
—
14 Sep 28
2023
1,530,000
19 Sep 22
0.096
—
19 Sep 27
Sub-total
2024
9,611,724
2023
8,739,398
Total
2024
11,101,284
2023
9,664,369
1 Represents a portion of Directors Fees sacrificed. These Share Rights vested on 30 June – Refer Section M of this report.
2 Represent Rights awarded under the Executive Incentive Plan which vest over three years on 30 June of the current and two subsequent financial years.
3 Duncan Lockhart resigned 31 August 2022.
4 Jonathan Snape resigned 20 January 2023. 740,742 of these Share Rights were subsequently cancelled and a further 185,185 did not vest.
5 Share Rights were issued to Directors in accordance with approvals obtained under ASX Listing Rule 10.14.
The following factors and assumptions were used in determining the fair value of rights granted to key management personnel during
FY2024:
14 Sep 20231
14 Sep 2028
$0.053
Nil
$0.053
N/A
N/A
—
14 Nov 20231
14 Nov 2028
$0.050
Nil
$0.050
N/A
N/A
—
14 Nov 20232
30 Jun 2028
$0.050
Nil
$0.050
N/A
N/A
—
1 EIP Rights for the plan year commencing 1 July 2022.
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
FY2023:
19 Sep 20221
19 Sep 2027
$0.096
Nil
$0.096
N/A
N/A
—
10 Nov 20221
10 Nov 2027
$0.083
Nil
$0.083
N/A
N/A
—
11 Nov 20222
30 Jun 2027
$0.084
Nil
$0.084
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.
Leon Devaney
2024
1,340,420
1,053,451
496,171
—
2,890,042
100%
Nil
2023
—
1,053,451
—
—
1,053,451
100%
Nil
Ross Evans
2024
731,135
574,478
405,655
—
1,711,268
100%
Nil
2023
—
574,478
—
—
574,478
100%
Nil
Damian Galvin
2024
483,175
379,405
243,198
—
1,105,778
100%
Nil
2023
—
379,405
—
—
379,405
100%
Nil
Duncan Lockhart3
2024
N/A
N/A
N/A
N/A
N/A
N/A
N/A
2023
—
76,283
—
—
76,283
100%
Nil
Jonathan Snape4
2024
N/A
N/A
N/A
N/A
N/A
N/A
N/A
2023
—
185,186
—
—
185,186
100%
Nil
Daniel White
2024
649,178
510,000
327,269
—
1,486,447
100%
Nil
2023
—
510,000
—
—
510,000
100%
Nil
2023
—
—
—
1,510,476
452,160
30%
70%
Total
2024
3,203,908
2,517,334
1,472,293
—
7,193,535
100%
Nil
2023
—
2,778,803
—
—
2,778,803
100%
Nil
2023
—
—
—
1,510,476
452,160
30%
70%
1 The number of Rights that vested in respect of plan year commencing 1 July 2020 relates to Share Rights granted in prior financial years under the Long Term
Incentive Plan.
2 The proportion of Rights vested represents the proportion of the maximum number of Rights that were eligible for vesting during the financial year.
3 Duncan Lockhart resigned 31 August 2022.
4 Jonathan Snape resigned 20 January 2023.
5 The FY2020 STIP was awarded as deferred share rights instead of cash. These rights vested 1 July 2023.
In addition, 1,489,560 Share Rights vested on 30 June 2024 (2023: 924,971), 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 F 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.
Non-Executive Directors were entitled to sacrifice up to 25% of their Base Fee to earn Share Rights which vested on 30 June.
Share Rights issued to Directors, and subsequent conversion to Ordinary Shares, are in accordance with approvals obtained under ASX
Listing Rule 10.14.
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
2024
N/A
N/A
N/A
N/A
N/A
N/A
N/A
2023
161,765
—
—
—
(161,765)
N/A
N/A
Stephen Gardiner
2024
379,040
386,182
—
(379,040)
N/A
386,182
—
2023
161,765
217,275
—
—
N/A
379,040
—
Katherine Hirschfeld
2024
86,910
—
—
(86,910)
N/A
—
—
2023
64,706
86,910
—
(64,706)
N/A
86,910
—
Agu Kantsler
2024
217,275
386,182
—
(217,275)
N/A
386,182
—
2023
161,765
217,275
—
(161,765)
N/A
217,275
—
Michael McCormack
2024
403,511
717,196
—
(403,511)
N/A
717,196
—
2023
300,420
403,511
—
(300,420)
N/A
403,511
—
Sub-total
2024
1,086,736
1,489,560
—
(1,086,736)
N/A
1,489,560
—
2023
850,421
924,971
—
(526,891)
(161,765)
1,086,736
—
Executives
Leon Devaney
2024
4,235,213
4,021,260
—
(2,128,311)
N/A
2,393,871
3,734,291
2023
1,074,860
3,160,353
—
—
N/A
1,632,140
2,603,073
Ross Evans
2024
2,129,089
2,193,405
—
(980,133)
N/A
1,305,613
2,036,748
2023
405,655
1,723,434
—
—
N/A
574,478
1,554,611
Damian Galvin
2024
1,381,413
1,449,525
—
(622,603)
N/A
862,580
1,345,755
2023
243,198
1,138,215
—
—
N/A
379,405
1,002,008
Duncan Lockhart2
2024
N/A
N/A
N/A
N/A
N/A
N/A
N/A
2023
304,213
76,283
(84,504)
—
(295,992)
N/A
N/A
Jonathan Snape3
2024
N/A
N/A
N/A
N/A
N/A
N/A
N/A
2023
—
1,111,113
(740,742)
—
(370,371)
N/A
N/A
Daniel White
2024
3,367,745
1,947,534
(1,058,316)
(1,289,429)
N/A
1,159,178
1,808,356
2023
2,820,949
1,530,000
(560,427)
(422,777)
N/A
510,000
2,857,745
Sub-total
2024
11,113,460
9,611,724
(1,058,316)
(5,020,476)
N/A
5,721,242
8,925,150
2023
4,848,875
8,739,398
(1,385,673)
(422,777)
(666,363)
3,096,023
8,017,437
Total
2024
12,200,196
11,101,284
(1,058,316)
(6,107,212)
N/A
7,210,802
8,925,150
2023
5,699,296
9,664,369
(1,385,673)
(949,668)
(828,128)
4,182,759
8,017,437
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
Leon Devaney
TBD1
Deferred Share Rights – FY2024 EIP1
—
—
165,260
14 Nov 2023
Deferred Share Rights – FY2023 EIP
1,340,420
30 Jun 2026
31,117
14 Nov 2023
Deferred Share Rights – FY2023 EIP
1,340,420
30 Jun 2025
17,872
14 Nov 2023
Deferred Share Rights – FY2023 EIP
1,340,420
30 Jun 2024
—
10 Nov 2022
Deferred Share Rights – FY2022 EIP
1,053,451
30 Jun 2025
17,175
10 Nov 2022
Deferred Share Rights – FY2022 EIP
1,053,451
30 Jun 2024
—
Ross Evans
TBD1
Deferred Share Rights – FY2024 EIP1
—
—
90,175
14 Sep 2023
Deferred Share Rights – FY2023 EIP
731,135
30 Jun 2026
17,991
14 Sep 2023
Deferred Share Rights – FY2023 EIP
731,135
30 Jun 2025
10,333
14 Sep 2023
Deferred Share Rights – FY2023 EIP
731,135
30 Jun 2024
—
19 Sep 2022
Deferred Share Rights – FY2022 EIP
574,478
30 Jun 2025
10,833
19 Sep 2022
Deferred Share Rights – FY2022 EIP
574,478
30 Jun 2024
—
Damian Galvin
TBD1
Deferred Share Rights – FY2024 EIP1
—
—
59,652
14 Sep 2023
Deferred Share Rights – FY2023 EIP
483,175
30 Jun 2026
11,890
14 Sep 2023
Deferred Share Rights – FY2023 EIP
483,175
30 Jun 2025
6,829
14 Sep 2023
Deferred Share Rights – FY2023 EIP
483,175
30 Jun 2024
—
19 Sep 2022
Deferred Share Rights – FY2022 EIP
379,405
30 Jun 2025
7,154
19 Sep 2022
Deferred Share Rights – FY2022 EIP
379,405
30 Jun 2024
—
Daniel White
TBD1
Deferred Share Rights – FY2024 EIP1
—
—
80,086
14 Sep 2023
Deferred Share Rights – FY2023 EIP
649,178
30 Jun 2026
15,974
14 Sep 2023
Deferred Share Rights – FY2023 EIP
649,178
30 Jun 2025
9,175
14 Sep 2023
Deferred Share Rights – FY2023 EIP
649,178
30 Jun 2024
—
19 Sep 2022
Deferred Share Rights – FY2022 EIP
510,000
30 Jun 2025
9,617
19 Sep 2022
Deferred Share Rights – FY2022 EIP
510,000
30 Jun 2024
—
Total
14,646,392
561,133
1 Share rights as part of the FY2024 EIP are expected to be granted during FY2025. 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 2024 quarterly report, which is calculated as 5.03 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 FY2024 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.
The Executive Share Option Plan was a historical plan granting management the right to exercise options at a given price during the period
1 July 2022 until 30 June 2023. No share options were exercised by 30 June 2023 and all options subsequently lapsed 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
2024
5,105,000
—
$0.20
01 Jul 2023
(5,105,000)
—
N/A
—
2023
5,105,000
—
$0.20
01 Jul 2023
—
—
N/A
5,105,000
Ross Evans
2024
4,170,025
—
$0.20
01 Jul 2023
(4,170,025)
—
N/A
—
2023
4,170,025
—
$0.20
01 Jul 2023
—
—
N/A
4,170,025
Damian Galvin
2024
2,750,000
—
$0.20
01 Jul 2023
(2,750,000)
—
N/A
—
2023
2,750,000
—
$0.20
01 Jul 2023
—
—
N/A
2,750,000
Duncan Lockhart1
2024
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
2023
3,333,333
—
$0.20
01 Jul 2023
—
—
(3,333,333)
N/A
Total
2024
12,025,025
—
$0.20
01 Jul 2023
(12,025,025)
—
N/A
—
2023
15,358,358
—
$0.20
01 Jul 2023
—
—
(3,333,333)
12,025,025
1 Duncan Lockhart resigned 31 August 2022.
Non-Executive Directors
Troy Harry1
2024
53,340,268
N/A
—
—
(53,340,268)
N/A
2023
N/A
53,340,268
—
—
N/A
53,340,268
Stephen Gardiner
2024
—
N/A
—
379,040
N/A
379,040
2023
—
N/A
—
—
N/A
—
Katherine Hirschfeld
2024
825,556
N/A
—
86,910
N/A
912,466
2023
760,850
N/A
—
64,706
N/A
825,556
Agu Kantsler
2024
161,765
N/A
—
217,275
N/A
379,040
2023
—
N/A
—
161,765
N/A
161,765
Michael McCormack
2024
300,420
N/A
—
403,511
N/A
703,931
2023
—
N/A
—
300,420
N/A
300,420
Sub-total
2024
54,628,009
—
—
1,086,736
(53,340,268)
2,374,477
2023
760,850
53,340,268
—
526,891
N/A
54,628,009
Other Key Management Personnel
Leon Devaney
2024
2,606,757
N/A
—
2,128,311
N/A
4,735,068
2023
2,606,757
N/A
—
—
N/A
2,606,757
Ross Evans
2024
386,184
N/A
—
980,133
N/A
1,366,317
2023
386,184
N/A
—
—
N/A
386,184
Damian Galvin
2024
141,000
N/A
—
622,603
N/A
763,603
2023
141,000
N/A
—
—
N/A
141,000
Daniel White
2024
2,985,420
N/A
—
1,289,429
N/A
4,274,849
2023
2,562,643
N/A
—
422,777
N/A
2,985,420
Sub-total
2024
6,119,361
—
—
5,020,476
—
11,139,837
2023
5,696,584
—
—
422,777
—
6,119,361
Total KMP
2024
60,747,370
—
—
6,107,212
(53,340,268)
13,514,314
2023
6,457,434
53,340,268
—
949,668
—
60,747,370
1 Troy Harry was appointed on 1 September 2022 and resigned on 5 February 2024.
The details of service agreements of the key management personnel of the Consolidated Entity as of 1 July 2024 are as follows:
Leon Devaney
Managing Director & Chief Executive Officer
Full time permanent
$595,000
6-months
Ross Evans
Chief Operations Officer
Full time permanent
$558,079
6-months
Damian Galvin
Chief Financial Officer
Full time permanent
$369,179
6-months
Daniel White
Group General Counsel & Company Secretary
Full time permanent
$495,639
3-months
1 Total Annual Fixed Remuneration, effective 1 July 2024 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 provides rights relating to
indemnity, insurance, and access to documents.
The table below summarises the Non-Executive Director fees for FY2024. 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 14 November 2023.
Chair
$130,000
Non-Executive Director
$70,000
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
18 September 2024
Audit & Financial Risk
Chair
$10,000
Member
$5,000
Remuneration & Nominations
Chair
$10,000
Member
$5,000
Risk & Sustainability
Chair
$10,000
Member
$5,000
Auditor’s Independence Declaration
As lead auditor for the audit of Central Petroleum Limited for the year ended 30 June 2024, 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
Brisbane
Partner
18 September 2024
PricewaterhouseCoopers
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 21. These pages are not part of these financial statements.
The financial statements were authorised for issue by the Directors on 18 September 2024. 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.
Revenue from contracts with customers – sale of hydrocarbons
2
37,154
39,255
Cost of sales
4(a)
(27,365)
(26,408)
Gross profit
9,789
12,847
Other income
3
14,754
1,880
Exploration expenditure
4(f)
(3,990)
(13,093)
General and administrative expenses net of recoveries
4(c)
(3,386)
(4,797)
Finance costs
4(d)
(4,293)
(4,797)
Other expenses
4(b)
(452)
—
Profit/(loss) before income tax
12,422
(7,960)
Income tax expense
5
—
—
Profit/(loss) for the year
12,422
(7,960)
Other comprehensive profit/(loss) for the year, net of tax
—
—
Total comprehensive profit/(loss) for the year
12,422
(7,960)
Total comprehensive profit/(loss) attributable to members of the parent entity
12,422
(7,960)
Earnings per share for profit or loss attributable to the ordinary equity
holders of the company:
Basic earnings/(loss) per share (cents)
22(a)
1.68
(1.09)
Diluted earnings/(loss) per share (cents)
22(b)
1.64
(1.09)
The accompanying notes form part of these financial statements.
ASSETS
Current assets
Cash and cash equivalents
7
24,985
13,826
Trade and other receivables
8
5,450
6,675
Inventories
9
3,765
3,550
Total current assets
34,200
24,051
Non-current assets
Property, plant and equipment
10
55,578
60,192
Right of use assets
11(a)
1,018
551
Exploration assets
12
7,674
7,999
Other intangible assets
13
376
332
Other financial assets
14
2,840
3,053
Goodwill
15
1,953
1,953
Total non-current assets
69,439
74,080
Total assets
103,639
98,131
LIABILITIES
Current liabilities
Trade and other payables
16
3,260
3,009
Deferred revenue
2(b)
1,087
3,536
Borrowings
17(a)
4,440
4,376
Lease liabilities
11(a)
624
426
Provisions
18
8,794
5,597
Total current liabilities
18,205
16,944
Non-current liabilities
Deferred revenue
2(b)
10,237
11,632
Borrowings
17(b)
18,723
23,150
Lease liabilities
11(a)
426
201
Provisions
18
23,493
26,816
Total non-current liabilities
52,879
61,799
Total liabilities
71,084
78,743
Net assets
32,555
19,388
EQUITY
Contributed equity
19 (a)
197,776
197,776
Reserves
20
41,488
31,433
Accumulated losses
21
(206,709)
(209,821)
Total equity
32,555
19,388
The accompanying notes form part of these financial statements.
Balance at 1 July 2022
197,776
30,615
—
(201,861)
26,530
Total loss for the year
—
—
—
(7,960)
(7,960)
Other comprehensive loss
—
—
—
—
—
Total comprehensive profit
for the year
—
—
—
(7,960)
(7,960)
Transactions with owners in
their capacity as owners
Share based payments
—
820
—
—
820
Share issue costs
—
(2)
—
—
(2)
—
818
—
—
818
Balance at 30 June 2023
197,776
31,433
—
(209,821)
19,388
Total profit for the year
—
—
—
12,422
12,422
Other comprehensive loss
—
—
—
—
—
Total comprehensive loss for
the year
—
—
12,422
12,422
Transactions with owners in
their capacity as owners
Share based payments
—
749
—
—
749
Share issue costs
—
(4)
—
—
(4)
—
745
—
—
745
Transfer of retained profits to
accumulated profits reserve
—
—
9,310
(9,310)
—
Balance at 30 June 2024
197,776
32,178
9,310
(206,709)
32,555
The accompanying notes form part of these financial statements.
Cash flows from operating activities
Receipts from customers
36,882
38,050
Interest received
912
519
Other income
3
248
Government grants
11
—
Interest and borrowing costs
(2,893)
(2,853)
Payments for exploration expenditure
(2,614)
(9,629)
Payments to other suppliers and employees
(25,439)
(28,391)
Net cash inflow/(outflow) from operating activities
27
6,862
(2,056)
Cash flows from investing activities
Payments for property, plant and equipment
(2,939)
(2,857)
Proceeds from sale of producing assets and property, plant and equipment
3
3
Proceeds from sale of subsidiary net of transaction costs and cash disposed
3(b)
12,184
—
Redemption of security deposits and bonds
201
1,356
Net cash inflow/(outflow) from investing activities
9,449
(1,498)
Cash flows from financing activities
Payments for the issue of securities
(4)
(2)
Proceeds from borrowings
28(b)
—
1,000
Repayment of borrowings
28(b)
(4,667)
(4,625)
Transaction costs related to borrowings
—
(195)
Principal elements of lease payments
28(b)
(481)
(445)
Net cash outflow from financing activities
(5,152)
(4,267)
Net increase/(decrease) in cash and cash equivalents
11,159
(7,821)
Cash and cash equivalents at the beginning of the financial year
13,826
21,647
Cash and cash equivalents at the end of the financial year
7
24,985
13,826
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 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 cash flow forecast scenarios prepared by management for the next twelve months and believe the Group has
sufficient cash flows and access to capital to continue operations as planned. During FY2024, the Group realised over $12 million cash from
the sale of its interest in the Range CSG assets in November 2023 and at year end had a cash balance of $25.0 million.
Central and its joint venturer continue to consider the future structure and timing of the three-well sub-salt exploration program following
the termination of previous farm-out funding arrangements. Central is progressing discussions with a credible party for potential farmins to
assist with funding the wells.
Alternatively, the relevant permit may be relinquished if funds are not available to satisfy specific permit commitments (any relinquishment
of interests would potentially impact the carrying value of relevant Exploration Assets).
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 2023 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 J 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 FY2024 was assessed against a recent market transaction
adopting the fair value less costs of disposal measurement methodology (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 have had historical impairments 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 and
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
10 – 40 years
Leasehold Improvements
4 – 10 years
Plant and Equipment
2 – 30 years
Motor Vehicles
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.
The Group assesses the recoverability of the carrying value of capitalised exploration and evaluation assets at each reporting date (or
during the year should the need arise). In completing this assessment, regard is given to the currency of the right of tenure over the area of
interest, the Group’s intentions with respect to proposed future exploration and development plans for the area of interest, to the success
or otherwise of activities undertaken in the area of interest, and to any potential plans for divestment. Exploration and evaluation
activities that have not yet reached a stage that permits reasonable assessment of the existence of economically recoverable reserves may
be subject to impairment 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 and directors 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.
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 from the proceeds, net of tax.
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 its annual reporting period commencing 1 July 2023:
•
AASB 2021-5 Amendments to Australian Accounting Standards – Deferred Tax related to Assets and Liabilities arising from a Single
Transaction [AASB 112]
•
AASB 2021-2 Amendments to Australian Accounting Standards – Disclosure of Accounting Policies Definition of Accounting Estimates
[AASB 7, AASB 101, AASB 108, AASB 134 & AASB Practice Statement 2].
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
30,963
34,731
Crude oil and condensate
3,155
3,488
Revenue released from Deferred Revenue 1
3,036
1,036
Total revenue from contracts with customers
37,154
39,255
1 Represents amounts paid for gas under 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
1,087
10,237
11,324
1,371
11,632
13,003
Deferred Revenue – other gas sales contracts1
—
—
—
2,165
—
2,165
Total contract liabilities
1,087
10,237
11,324
3,536
11,632
15,168
1 Refer Note 1(e) (i) and (iii).
Carrying amount at 1 July 2023
13,003
2,165
15,168
Revenue recognised from the delivery of gas
(331)
(2,105)
(2,436)
Revenue released (forfeited gas)
(2,901)
(135)
(3,036)
Gas paid for but not taken during the period
1,553
–
1,553
Finance charges
–
75
75
Carrying amount at 30 June 2024
11,324
—
11,324
Interest
947
533
Income from financial assets at amortised cost
—
304
Income from the farmout of exploration interests (a)
—
795
Profit on disposal of subsidiary (b)
13,795
—
Government subsidies
11
—
Profit on disposal of inventory and other assets
1
248
Total other income
14,754
1,880
On 31 March 2023 the Group completed the farmout of interests in certain exploraƟon permits to Peak Helium (Amadeus Basin) Pty Ltd. In
accordance with the Farmout Agreement, the Group was enƟtled to receive reimbursement of expenditure previously incurred and
expensed by the Group from the effecƟve date of the farmout transacƟon (1 October 2021). A total of $795,000 was recorded as Other
Income in the prior year relaƟng to the farmout of exploraƟon interests. This amount reflected reimbursement amounts relaƟng to the
previous financial year (FY 2022) exploraƟon expenditure and reducƟons in rehabilitaƟon obligaƟons previously expensed.
On 30 November 2023, the Group completed the sale of its 50% interest in the Range Gas Project (ATP 2031) in Queensland’s Surat Basin
by way of the sale of its wholly owned subsidiary, Central Petroleum Eastern Pty Ltd. Details of the disposal were as follows:
Cash consideration received net of cash disposed
12,457
Transaction costs
(273)
Net cash received
12,184
Net liabilities of Central Petroleum Eastern Pty Ltd at date of disposal
1,611
Profit on disposal
13,795
Depreciation and amortisation
4(e)
6,748
6,295
Employee and contractor costs
5,963
5,326
Gas purchases
4,894
4,416
Other production costs
4,672
5,073
Royalties
3,104
2,938
Transportation and storage
1,984
2,360
Total cost of sales
27,365
26,408
Write off, impairment, and disposal of property, plant and equipment
442
—
Other costs
10
—
Total other expenses
452
—
Depreciation and amortisation
4(e)
598
571
Employee and contractor costs
1,334
1,650
Share based payments
749
820
Other costs
705
1,756
Total general and administrative expenses
3,386
4,797
Interest and fees on debt facilities
2,865
2,998
Interest on lease liabilities
11(b)
43
49
Amortisation of deferred finance costs
291
342
Accretion charges
1,094
1,408
Total finance costs
4,293
4,797
Depreciation
Buildings
10
176
175
Producing assets
10
3,485
3,371
Plant and equipment
10
3,100
2,752
Leasehold improvements
10
10
10
Right of use assets
11(b)
437
442
Total depreciation
7,208
6,750
Amortisation
Other intangible assets - software
13
138
116
Impairment expenses of $325,000 were recognised during the year for costs carried forward in respect of the Palm Valley Deep prospect.
In FY2023, impairment expenses of $3,486,000 relating to the impairment of the Group’s interest in RL3 and RL4 ($398,000) and
impairment of amounts owing by Peak Helium (Amadeus Basin) Pty Ltd under farmin arrangements ($3,088,000) were included in
exploration expenditure.
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
—
—
Profit/(Loss) before income tax expense
12,422
(7,960)
Prima facie tax (expense)/benefit at 30% (2023: 30%)
(3,726)
2,388
Tax effect of amounts which are not deductible in calculating taxable income:
Non-deductible expenses
(8)
(8)
Share based payments
(225)
(246)
Other items
—
—
Sub-total
(3,959)
2,134
Previously unrecognised deferred tax assets
3,959
—
Deferred tax assets not recognised
—
(2,134)
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
1
1
Deferred tax assets not recognised
(1)
(1)
Net amounts recognised directly in equity
—
—
Unutilised tax losses for which no deferred tax asset has been recognised
131,696
142,134
Potential tax benefit at 30%
39,509
42,640
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
10,072
9,788
Receivables
—
926
Deferred revenue
—
187
Other expenditure
294
253
Borrowing costs
78
140
Unutilised losses
48,643
51,936
Total deferred tax assets before set-offs
59,087
63,230
Set-off of deferred tax liabilities pursuant to set-off provisions
(9,134)
(9,296)
Net deferred tax assets not recognised
49,953
53,934
Movements in deferred tax assets
Opening balance at 1 July
9,296
9,487
Charged to the income statement
(162)
(191)
Closing balance at 30 June
9,134
9,296
Deferred tax assets to be recovered after more than 12-months
6,051
6,241
Deferred tax assets to be recovered within 12-months
3,083
3,055
9,134
9,296
Deferred tax liabilities
Capitalised exploration
2,271
2,362
Property, plant and equipment
6,863
6,929
Other items
—
5
Total deferred tax liabilities before set-offs
9,134
9,296
Set-off of deferred tax assets pursuant to set-off provisions
(9,134)
(9,296)
Net deferred tax liabilities
—
—
Movements in deferred tax liabilities
Opening balance at 1 July
9,296
9,487
Credited to the income statement
(162)
(191)
Closing balance at 30 June
9,134
9,296
Deferred tax liabilities to be recovered after more than 12-months
8,947
9,173
Deferred tax liabilities to be recovered within 12-months
187
123
9,134
9,296
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
241,450
243,958
(ii) Taxation services
Income tax compliance
15,300
14,280
Other tax related services
21,581
47,512
Total taxation services
36,881
61,792
Total remuneration of PwC
278,331
305,750
Cash and cash equivalents
24,985
13,826
Made up as follows:
Corporate cash and bank balances (a)
14,567
13,296
Joint arrangements (b)
418
530
Cash on term deposit (c)
10,000
—
Total cash and cash equivalents
24,985
13,826
(a) $2,759,000 of this balance relates to cash held with Macquarie Bank Limited to be used for allowable purposes under the Facility
Agreement (2023: $2,920,000), 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.
(c) Cash on term deposit is held to meet short term cash needs and there is no significant risk of a change in value as a result of early
withdrawal.
The Group’s exposure to credit and interest rate risk is discussed in Note 32.
Current
Trade debtors
17
55
Accrued income and recoveries (a)
3,943
3,963
Other receivables
1
545
Prepayments
1,489
1,361
Items measured at amortised cost:
Deferred receivable from partial sale of producing assets (b)
—
751
5,450
6,675
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.
This was classified as a Financial Asset measured at amortised cost. During the year, $751,000 was recouped through a free carry by
the purchasers of Central’s share of expenditure on certain exploration and development projects (2023: $20,373,000). In FY 2023,
$304,000 was recognised as Other Income as a result of adjustments to amortised cost for the period (Current Year:Nil).
Crude oil and natural gas
132
108
Spare parts and consumables
1,744
1,412
Drilling materials and supplies at cost
1,889
2,030
3,765
3,550
Year ended 30 June 2023
Opening net book amount
754
33,372
19,720
53,846
Additions
—
8,346
4,469
12,815
Changes to rehabilitation estimates
—
(168)
10
(158)
Disposals and write offs
—
—
(3)
(3)
Depreciation charge
(175)
(3,371)
(2,762)
(6,308)
Closing net book amount
579
38,179
21,434
60,192
At 30 June 2023
Cost
1,952
64,442
47,779
114,173
Accumulated depreciation
(1,373)
(26,263)
(26,345)
(53,981)
Net book amount at 30 June 2023
579
38,179
21,434
60,192
Year ended 30 June 2024
Opening net book amount
579
38,179
21,434
60,192
Additions
—
353
2,365
2,718
Changes to rehabilitation estimates
—
(110)
(3)
(113)
Disposals and write offs
—
—
(448)
(448)
Depreciation charge
(176)
(3,485)
(3,110)
(6,771)
Closing net book amount
403
34,937
20,238
55,578
At 30 June 2024
Cost
1,952
64,685
49,476
116,113
Accumulated depreciation
(1,549)
(29,748)
(29,238)
(60,535)
Net book amount at 30 June 2024
403
34,937
20,238
55,578
At 30 June 2024, $839,000 of property plant and equipment balances relates to assets under construction and is not subject to
depreciation until complete (2023: $2,891,000).
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
951
483
Plant & Equipment
67
68
1,018
551
Lease Liabilities
Current
624
426
Non-current
426
201
1,050
627
Additions to the right-of-use assets during the 2024 financial year were $904,000 (2023: $77,000). Disposals and incentive adjustments
amounted to $Nil (2023: $6,000).
The statement of profit or loss shows the following amounts relating to leases:
Depreciation charge of right-of-use assets
Land & Buildings
368
373
Plant & Equipment
69
69
Total depreciation of right-of-use assets
437
442
Interest expense
43
49
Expense related to short term leases included in cost of sales and general and
administrative expenses (Note 4(g))
—
—
The total cash outflow for leases in 2024 was $524,000 (2023: $493,000).
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 and a bank guarantee held in respect of the Brisbane office lease. 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
7,674
7,999
Movement for the year:
Balance at the beginning of the year
7,999
8,397
Impairment expense (Note 4(f))
(325)
(398)
Balance at the end of the year
7,674
7,999
Software
At the beginning of the year
Cost
1,094
1,025
Accumulated amortisation
(762)
(646)
Net book value
332
379
Movements for the year
Opening net book amount
332
379
Additions
182
69
Amortisation
(138)
(116)
Closing net book amount
376
332
At the end of the year
Cost
1,050
1,094
Accumulated amortisation
(674)
(762)
Net book value
376
332
Non-Current
Security bonds on exploration permits and rental properties
2,840
3,053
Security bonds are provided to State or Territory governments in respect of certain performance obligations arising from awarded
petroleum and mineral tenements. These bonds are typically provided as cash or as bank guarantees in favour of the State or Territory
government. Bank guarantees covering these bonds and rental properties are 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 February 2024 New Zealand Oil & Gas (now renamed Echelon Resources Limited) and Horizon Oil Limited entered into agreements with
Macquarie Mereenie Pty Ltd to acquire the latter’s interests in the Mereenie gas field with an effective date of 1 April 2023. The
transaction completed on 11 June 2024.
Management and the Board have concluded that the transaction provides evidence to support the fair value of the Mereenie, Palm Valley
and Dingo fields which constitute the Amadeus Basin assets (‘the Assets’) and will therefore adopt the fair value less costs of disposal
measurement methodology as at 30 June 2024. This change in estimate from the future cash flows method applied previously, to the
recent market transaction approach, is due to the transaction representing a more reliable estimate of the fair value of the Assets.
Management and the Board believe the transaction meets the requirements of an orderly transaction where all parties were acting in their
own economic best interests and therefore can be relied upon to determine a fair value for the Group’s interests in the Assets on a
reserves valuation basis. Management have taken the implied 2P reserves multiple from the transaction of $1.14 per GJ (including
maximum possible deferred consideration) and applied this across the Group’s interest of 2P reserves across the Assets. The Group’s 2P
reserves of 73.3 PJ attributed to the Assets used to underpin this assessment are obtained from an independent reserves report. From the
assessment performed, it was determined that the value of the transaction consideration on 2P Reserves Basis, when applied to Central’s
2P gas reserves, exceeds the net carrying value of the Group’s interests in the Assets and the associated goodwill.
On this basis Management and the Board have concluded there is no impairment of the carrying value of Goodwill or other producing
assets at 30 June 2024.
Fair Value Measurement is governed by AASB 13 which defines fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at the measurement date. It assumes the asset or liability is
exchanged in an orderly transaction between market participants at the measurement date under current market conditions. The fair value
measurement of the Assets falls under Level 2 of the fair value hierarchy. This classification is based on observable inputs other than
quoted prices in active markets for identical assets or liabilities. The inputs used in the valuation include market multiples derived from
comparable transactions, which are observable and verifiable.
Current
Trade payables
1,133
878
Other payables
—
5
Accruals
2,127
2,126
3,260
3,009
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
4,440
4,376
(b)
Non-current1
Debt facilities
18,723
23,150
1 Details regarding interest bearing liabilities are contained in Note 32(e).
The financing facility held with Macquarie Bank matures on 30 September 2025. The Group is in active discussions to refinance the facility.
Employee entitlements (a)
5,092
708
5,800
4,365
763
5,128
Restoration and rehabilitation (b)
2,831
22,047
24,878
370
24,460
24,830
Joint Venture production over-lift (c)
871
738
1,609
862
1,593
2,455
8,794
23,493
32,287
5,597
26,816
32,413
(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
5,128
24,830
2,455
32,413
Change in provision charged/(credited) to property,
plant and equipment
—
(113)
—
(113)
Additional provisions charged to profit or loss
3,009
889
26
3,924
Unwinding of discount
—
1,019
—
1,019
Disposal of subsidiary (Note 3 (b))
—
(1,569)
—
(1,569)
Amounts used during the year
(2,337)
(178)
(872)
(3,387)
Carrying amount at end of year
5,800
24,878
1,609
32,287
740,147,003 fully paid ordinary shares (2023: 729,405,268)
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
729,405,268
725,907,449
197,776
197,776
Shares issued under Employee Incentive Plans
10,741,735
3,497,819
—
—
Balance at end of year
740,147,003
729,405,268
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
—
(17,221,046)
—
—
Total
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 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, F 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
22 May 2024
1 Jul 2018
72,877
—
(6,123)
(66,754)
—
Employee LTIP rights
12 Nov 2024
1 Jul 2018
578,689
—
—
(578,689)
—
Employee LTIP rights
30 Jun 2024
1 Jul 2019
319,033
—
(157,897)
(161,136)
—
Employee Deferred Share rights1
30 Jun 2025
1 Jul 2019
3,360,571
—
—
(3,360,571)
—
Employee LTIP rights
30 Jun 2025
1 Jul 2020
8,701,069
—
(5,880,323)
(2,709,046)
111,700
Employee LTIP rights
30 Jun 2026
1 Jul 2021
374,901
—
(42,685)
—
332,216
Employee LTIP rights
30 Jun 2027
1 Jul 2022
507,180
—
(59,171)
—
448,009
Employee LTIP rights
30 Jun 2028
1 Jul 2023
—
1,051,206
(86,656)
—
964,550
Executive Incentive Plan
EIP Share Rights
30 Jun 2027
1 Jul 2021
7,813,471
—
—
(2,778,803)
5,034,668
EIP Share Rights
30 Jun 2028
1 Jul 2022
—
9,611,724
—
—
9,611,724
Non-Executive Director rights 2
Director Share Rights
30 Jun 2026
1 Jul 2021
161,765
—
—
(161,765)
—
Director Share Rights
30 Jun 2027
1 Jul 2022
924,971
—
—
(924,971)
—
Director Share Rights
30 Jun 2028
1 Jul 2023
—
1,489,560
—
—
1,489,560
Total
22,814,527
12,152,490
(6,232,855)
(10,741,735)
17,992,427
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
had 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
32,178
31,433
Accumulated profits reserve
9,310
—
Total Reserves
41,488
31,433
Movements
Share options
reserve
Accumulated
profits reserve
Balance at 1 July 2022
30,615
—
Share based payments relating to employee incentive plans (a)
820
—
Transaction costs
(2)
—
Balance at 30 June 2023
31,433
—
Share based payments relating to employee incentive plans (a)
749
—
Transaction costs
(4)
—
Transfer of profit during the period from accumulated losses (b)
—
9,310
Balance at30 June 2024
32,178
9,310
(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.
(b)
The accumulated profits reserve acts to quarantine profits of the Company generated in the current or prior periods.
Movements in accumulated losses were as follows:
Balance at the start of year
(209,821)
(201,861)
Net profit/(loss) for the year
12,422
(7,960)
Transfer of profits to accumulated profits reserve
(9,310)
—
Balance at end of year
(206,709)
(209,821)
(a)
Basic earnings/(loss) per share (cents)
1.68
(1.09)
(b)
Diluted earnings/(loss) per share (cents)
1.64
(1.09)
(c)
Profit/(Loss) used in earnings per share calculation
Profit/(loss) attributed to ordinary equity holders ($’000)
12,422
(7,960)
(d)
Weighted average number of ordinary shares
Weighted average number of shares used as the denominator in
calculating basic loss/earnings per share
737,684,614
728,113,749
Adjustments for the calculation of diluted loss/earnings per share:
Employee share rights
20,948,527
—
Weighted average number of shares used as the denominator in
calculating diluted loss/earnings per share
758,633,141
728,113,749
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
30,963
—
—
30,963
Crude oil and condensate
3,155
—
—
3,155
Forfeited take or pay amounts
3,036
—
—
3,036
Total revenue from contracts with customers
37,154
—
—
37,154
Cost of sales
(27,365)
—
—
(27,365)
Gross profit
9,789
—
—
9,789
Other income1
239
13,798
717
14,754
Other expenses
(452)
—
—
(452)
Exploration expenditure
(169)
(3,821)
—
(3,990)
Finance costs
(3,930)
(96)
(267)
(4,293)
General and administrative expenses2
—
—
(3,386)
(3,386)
Statutory profit / (loss) before income tax
5,477
9,881
(2,936)
12,422
Taxes
—
—
—
—
Statutory profit / (loss) for the year
5,477
9,881
(2,936)
12,422
Add finance costs net of interest income
3,703
93
(450)
3,346
Add depreciation, amortisation and impairment
7,190
—
598
7,788
Add exploration expenditure
169
3,821
—
3,990
EBITDAX3
16,539
13,795
(2,788)
27,546
Segment assets
69,754
9,169
24,716
103,639
Segment liabilities
(56,377)
(5,509)
(9,198)
(71,084)
Capital expenditure
Property, plant and equipment
2,651
—
67
2,718
Intangibles
164
—
18
182
Total capital expenditure
2,815
—
85
2,900
1 Other Income attributable to the Exploration Assets segment includes $13,795,000 relating to the sale of the Group’s 50% interest in the Range Gas Project (ATP
2031) in Queensland’s Surat Basin by way of the sale of its wholly owned subsidiary, Central Petroleum Eastern Pty Ltd. (Refer Note 3(b)).
2 Includes share based payments of $749,000 which is a non-cash item.
3 EBITDAX is earnings before interest, taxation, depreciation, amortisation, impairment and exploration expense.
Revenue from contracts with customers
Natural gas
34,731
—
—
34,731
Crude oil and condensate
3,488
—
—
3,488
Forfeited take or pay amounts
1,036
—
—
1,036
Total revenue from contracts with customers
39,255
—
—
39,255
Cost of sales
(26,408)
—
—
(26,408)
Gross profit
12,847
—
—
12,847
Other income1
556
977
347
1,880
Exploration expenditure
(6,862)
(6,231)
—
(13,093)
Finance costs
(4,446)
(63)
(288)
(4,797)
General and administrative expenses2
—
—
(4,797)
(4,797)
Statutory profit / (loss) before income tax
2,095
(5,317)
(4,738)
(7,960)
Taxes
—
—
—
—
Statutory profit / (loss) for the year
2,095
(5,317)
(4,738)
(7,960)
Add Finance costs net of interest income
3,965
54
(59)
3,960
Add Depreciation, amortisation and impairment
6,295
—
571
6,866
Add Exploration expenditure
6,862
6,231
—
13,093
EBITDAX3
19,217
968
(4,226)
15,959
Segment assets
74,344
9,968
13,819
98,131
Segment liabilities
(64,310)
(5,768)
(8,665)
(78,743)
Capital expenditure
Property, plant and equipment
12,690
—
125
12,815
Intangibles
56
—
13
69
Total capital expenditure
12,746
—
138
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 Includes share based payments of $820,000 which is a non-cash item.
3 EBITDAX is earnings before interest, taxation, depreciation, amortisation, impairment and exploration expense.
Revenue from external customers by geographical location of production:
Australia
37,154
39,255
Non-current assets by geographical location:
Australia
69,439
74,080
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
22,774
61%
15,068
38%
Second largest customer
4,414
12%
5,762
15%
Third largest customer
—
—
4,183
11%
Fourth largest customer
—
—
3,923
10%
The individual financial summary statements for the Parent Entity show the following aggregate amounts:
Balance Sheet
Current assets
27,182
15,098
Non-current assets
18,011
18,311
Total assets
45,193
33,409
Current liabilities
(8,488)
(6,609)
Non-current liabilities
(994)
(1,144)
Total liabilities
(9,482)
(7,753)
Net assets
35,711
25,656
Shareholders’ equity
Issued capital
197,776
197,776
Reserves
41,488
31,433
Accumulated losses
(203,553)
(203,553)
Total equity
35,711
25,656
Profit for the year
9,310
2,227
Total comprehensive profit
9,310
2,227
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
Western Australia
Ordinary
100
100
Central Petroleum Projects Pty Ltd
Western Australia
Ordinary
100
100
Helium Australia Pty Ltd
Victoria
Ordinary
100
100
Ordiv Petroleum Pty Ltd
Western Australia
Ordinary
100
100
Frontier Oil & Gas Pty Ltd
Western Australia
Ordinary
100
100
Central Petroleum Eastern Pty Ltd1
Western Australia
Ordinary
—
100
Central Geothermal Pty Ltd
Western Australia
Ordinary
100
100
Central Petroleum Services Pty Ltd
Western Australia
Ordinary
100
100
Central Petroleum PVD Pty Ltd
Queensland
Ordinary
100
100
Central Petroleum (NT) Pty Ltd
Queensland
Ordinary
100
100
Jarl Pty Ltd
Queensland
Ordinary
100
100
Central Petroleum Mereenie Pty Ltd
Queensland
Ordinary
100
100
Central Petroleum Mereenie Unit Trust
N/A
Units
100
100
Central Petroleum WS (NO 1) Pty Ltd
Queensland
Ordinary
100
100
Central Petroleum WS (NO 2) Pty Ltd
Queensland
Ordinary
100
100
1 Central Petroleum Eastern Pty Ltd was disposed on 30 November 2023. Refer Note 3(b)
Short-term employee benefits
2,846,432
2,944,399
Post-employment benefits
151,981
165,023
Long-term benefits
43,558
37,775
Share based payments
613,904
520,613
3,655,875
3,667,810
Detailed remuneration disclosures are provided in the Remuneration Report on pages 29 to 43.
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
Merlin Energy Pty Ltd
Central Petroleum Projects Pty Ltd
Helium Australia Pty Ltd
Ordiv Petroleum Pty Ltd
Frontier Oil & Gas Pty Ltd
Central Petroleum Services Pty Ltd
Central Geothermal Pty Ltd
Central Petroleum (NT) Pty Ltd
Central Petroleum PVD Pty Ltd
Central Petroleum Mereenie Pty Ltd
Jarl Pty Ltd
Central Petroleum WS (NO 2) 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 2024.
Revenue from the sale of goods
19,670
20,783
Cost of sales
(13,502)
(15,952)
Gross profit
6,168
4,831
Other income
14,716
1,854
Other expenses
(458)
—
Exploration expenses
(3,505)
(13,011)
Finance costs
(2,346)
(1,626)
General and administrative expenses
(3,376)
(4,376)
Profit/(loss) before income tax
11,199
(12,328)
Income tax credit
271
1,567
Profit/(loss) for the year
11,470
(10,761)
Other comprehensive profit/(loss) for the year, net of tax
—
—
Total comprehensive (loss)/profit for the year
11,470
(10,761)
Accumulated losses at the beginning of the financial year
(221,614)
(210,853)
Profit/(loss) for the year
11,470
(10,761)
Transfer to Accumulated Profits Reserve
(9,310)
—
Accumulated losses at the end of the financial year
(219,454)
(221,614)
Set out below is a consolidated balance sheet of the closed group as at 30 June.
ASSETS
Current assets
Cash and cash equivalents
24,752
13,718
Trade and other receivables
3,969
4,806
Inventories
2,630
2,613
Total current assets
31,351
21,137
Non-current assets
Property, plant and equipment
26,111
30,323
Right of use assets
678
512
Exploration assets
7,674
7,999
Other intangible assets
284
265
Other financial assets
2,046
2,259
Deferred Tax Assets
5,387
5,178
Goodwill
1,953
1,953
Total non-current assets
44,133
48,489
Total assets
75,484
69,626
LIABILITIES
Current liabilities
Trade and other payables
11,159
14,113
Deferred revenue
992
1,006
Borrowings
1,479
2,639
Lease liabilities
617
396
Provisions
7,658
4,508
Total current liabilities
21,905
22,662
Non-current liabilities
Deferred revenue
10,237
11,572
Borrowings
11,014
12,163
Lease liabilities
84
186
Provisions
12,434
15,448
Total non-current liabilities
33,769
39,369
Total liabilities
55,674
62,031
Net assets
19,810
7,595
EQUITY
Contributed equity
197,776
197,776
Reserves
41,488
31,433
Accumulated losses
(219,454)
(221,614)
Total equity
19,810
7,595
Profit/(loss) after income tax
12,422
(7,960)
Adjustments for:
Depreciation and amortisation
7,346
6,866
Impairment
325
3,486
Profit on disposal of subsidiary
(13,795)
—
Loss on disposal and write off of non-current assets
445
—
Exploration costs funded by Joint Venture partners
89
7,421
Share-based payments
749
820
Financing costs and interest (non-cash)
1,398
1,641
Changes in assets and liabilities relating to operating activities:
Decrease in trade and other receivables
474
129
(Increase)/decrease in inventories
(215)
317
Increase/(decrease) in trade and other payables
1,007
(10,681)
Decrease in deferred revenue
(3,919)
(4,324)
Increase in provisions
536
229
Net cash inflow/(outflow) from operations
6,862
(2,056)
During the year, the purchasers of 50% of the Group’s interests in the Amadeus Basin producing properties funded $663,000 (2023:
$9,863,000) of the Group’s share of costs for the acquisition of property, plant and equipment. These amounts formed part of the
deferred consideration component of the sale proceeds which have now been fully recovered.
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
24,985
13,826
Borrowings and leases – repayable within one year
(5,064)
(4,802)
Borrowings and leases – repayable after one year
(19,149)
(23,351)
Net cash / (debt)
772
(14,327)
Cash
24,985
13,826
Gross Debt – fixed interest rates
(1,050)
(627)
Gross debt – variable interest rates
(23,163)
(27,526)
Net cash / (debt)
772
(14,327)
Net debt 1 July 2022
21,647
(30,809)
(1,001)
(10,163)
Cash flows
(7,821)
3,625
445
(3,751)
Amortisation of deferred borrowing costs
—
(342)
—
(342)
Non-cash lease adjustments
—
—
(71)
(71)
Net cash/(debt) 30 June 2023
13,826
(27,526)
(627)
(14,327)
Cash flows
11,159
4,667
481
16,307
Amortisation of deferred borrowing costs
—
(291)
—
(291)
Non-cash adjustments
—
(13)
(904)
(917)
Net cash/(debt) 30 June 2024
24,985
(23,163)
(1,050)
772
The Consolidated Entity had contingent liabilities at 30 June 2024 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 (2023: $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.
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. Therefore, no value has been ascribed to this contingent liability at 30 June 2024.
On 26 July 2024 a new Gas Sales Agreement was executed by the Palm Valley Joint Venture partners for the supply of gas from 1
January 2025. The contracted price may result in this contingent liability becoming payable in future periods in respect of gas
supplied from the Palm Valley field.
The Consolidated Entity has the following capital expenditure commitments:
The following amounts are due:
Within one year
378
1,241
378
1,241
The Consolidated Entity has contingent exploration expenditure commitments on various permit areas
held through joint venture arrangements in Australia:
The following amounts are due:
Within one year
20,850
7,200
Later than one year but not later than three years
9,000
8,223
Later than three years but not later than five years
—
—
29,850
15,423
The value and timing of 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
30 Jun 20231
12,116,046
—
$0.20
$0.120
(12,116,046)
—
—
07 Nov 2019
30 Jun 20231
5,105,000
—
$0.20
$0.087
(5,105,000)
—
Totals
17,221,046
—
$0.111
(17,221,046)
—
—
Weighted average exercise price
$0.20
—
20 Aug 2019
30 Jun 2023
12,116,046
—
$0.20
$0.120
—
12,116,046
—
07 Nov 2019
30 Jun 2023
5,105,000
—
$0.20
$0.087
—
5,105,000
—
Totals
17,221,046
—
$0.111
—
17,221,046
—
Weighted average exercise price
$0.20
$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 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
3,360,571
—
$0.130
(3,360,571)
—
—
11 Nov 2020
30 Jun 20201
3,692,054
—
$0.130
—
(331,483)
3,360,571
1 Share rights in respect of the performance period ended 30 June 2020 had a deferred vesting date of 1 July 2023.
Under the Non-Executive Director offers, 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:
14 Nov 2023
30 Jun 2024
—
1,489,560
$0.050
—
—
1,489,560
23 Nov 2022
30 Jun 2023
924,971
—
$0.084
(924,971)
—
—
23 Nov 2021
30 Jun 2022
161,765
—
$0.115
(161,765)
—
—
23 Nov 2022
30 Jun 2023
—
924,971
$0.084
—
—
924,971
23 Nov 2021
30 Jun 2022
850,421
—
$0.115
(688,656)
—
161,765
The weighted average remaining contractual life of outstanding Non-Executive Director share rights at the end of the year was 4.0 years
(2023: 3.9 years).
Key Management Personnel are 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)
33% is paid at that time (i.e. at the end of the initial 12-month performance period); and
ii)
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
4,653,118
—
$0.096
(1,725,352)
—
1,463,883
1,463,883
10 Nov 2022 30 Jun 2022
3,160,353
—
$0.083
(1,053,451)
—
1,053,451
1,053,451
14 Sep 2023
30 Jun 2023
—
5,590,464
$0.053
—
—
1,863,488
3,726,976
14 Nov 2023 30 Jun 2023
—
4,021,260
$0.050
—
—
1,340,420
2,680,840
Totals
7,813,471
9,611,724
$0.065
(2,778,803)
—
5,721,242
8,925,150
19 Sep 2022 30 Jun 2022
—
5,579,045
$0.096
—
(925,927)
1,725,352
2,927,766
10 Nov 2022 30 Jun 2022
—
3,160,353
$0.083
—
—
1,053,451
2,106,902
Totals
—
8,739,398
$0.091
—
(925,927)
2,778,803
5,034,668
The weighted average fair value of share rights issued to key management personnel under the EIP during the financial year was $0.052
(2023: $0.091). The weighted average remaining contractual life of outstanding Executive Incentive Plan share rights at the end of the year
was 3.94 years (2023 4.0 years).
At 30 June 2024, no rights had been granted under the EIP for the plan year ended 30 June 2024. Share rights, as part of the FY2024 EIP
are expected to be granted during FY2025. 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:
11 Aug 2023 30 Jun 2024
—
1,019,157
$0.051
—
(86,656)
932,501
13 Sep 2023 30 Jun 2024
—
32,049
$0.059
—
—
32,049
22 Aug 2022 30 Jun 2023
507,180
$0.090
—
(59,171)
448,009
22 Aug 2022 30 Jun 2022
55,257
$0.090
—
(9,901)
45,356
17 Aug 2021 30 Jun 2022
319,644
—
$0.105
—
(32,784)
286,860
24 Jul 2020
30 Jun 2021
8,360,299
—
$0.065
(2,402,287)
(5,857,649)
100,363
24 Jul 2020
30 Jun 2021
340,770
—
$0.089
(306,759)
(22,674)
11,337
07 Nov 2019 30 Jun 2019
578,689
—
$0.119
(578,689)
—
—
23 Aug 2019 30 Jun 2020
23,988
—
$0.190
(22,140)
(1,848)
—
23 Aug 2019 30 Jun 2020
295,045
—
$0.155
(138,996)
(156,049)
—
09 May 2019 30 Jun 2019
28,012
—
$0.101
(28,012)
—
—
24 Sep 2019 30 Jun 2019
8,127
—
$0.087
(8,127)
—
—
24 Sep 2019 30 Jun 2019
36,738
—
$0.120
(30,615)
(6,123)
—
Totals
10,553,749
1,051,206
(3,515,625)
(6,232,855)
1,856,475
The weighted average fair value of share rights granted under the Long Term Incentive Plan during the year was $0.051 (2023: $0.09). The
weighted average remaining contractual life of outstanding share rights at the end of the year was 3.2 years (2023: 2.1 years).
The fair values of deferred share rights granted are valued using methodology that takes into account market and 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.
22 Aug 2022 30 Jun 2023
—
540,992
$0.090
—
(33,812)
507,180
22 Aug 2022 30 Jun 2022
—
61,476
$0.090
—
(6,219)
55,257
17 Aug 2021 30 Jun 2022
426,192
—
$0.105
—
(106,548)
319,644
18 Sep 2020 30 Jun 2018
1,198
—
$0.130
(1,198)
—
—
24 Jul 2020
30 Jun 2021
8,620,660
—
$0.065
—
(260,361)
8,360,299
24 Jul 2020
30 Jun 2021
454,140
—
$0.089
—
(113,370)
340,770
24 Jul 2020
30 Jun 2020
30,545
—
$0.089
(26,553)
(3,992)
—
07 Nov 2019 30 Jun 2019
578,689
—
$0.119
—
—
578,689
23 Aug 2019 30 Jun 2020
274,119
—
$0.190
(220,611)
(29,520)
23,988
23 Aug 2019 30 Jun 2020
6,003,654
—
$0.155
(2,286,515)
(3,422,094)
295,045
09 May 2019 30 Jun 2019
28,012
—
$0.101
—
—
28,012
24 Sep 2019 30 Jun 2019
259,406
—
$0.087
(251,279)
—
8,127
24 Sep 2019 30 Jun 2019
65,987
—
$0.120
(17,356)
(11,893)
36,738
01 Sep 2017 30 Jun 2018
5,651
—
$0.115
(5,651)
—
—
Totals
16,748,253
602,468
(2,809,163)
(3,987,809)
10,553,749
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
749,453
820,165
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 2024 is nil (2023: nil), no loss allowance provision has been recorded at 30 June 2024 (2023: nil).
The Consolidated Entity trades only with recognised banks and large customers where the credit risk is considered minimal.
Customer credit risk is managed in accordance with the Group’s established policy, procedures and controls. Outstanding customer
receivables are regularly monitored and relate to the Groups’ customers for which there is no history of credit risk or overdue payments.
An impairment analysis is performed at each reporting date on an individual basis for the major customers.
The aging of the Consolidated Entity’s trade receivables at reporting date was:
Current: 0-30 days
3,868
4,563
—
—
3,868
4,563
—
—
The trade receivables at 30 June 2024 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
24,985
—
—
—
24,985
24,985
Trade and other receivables
3,961
—
—
—
3,961
3,961
Other financial assets
—
—
2,840
—
2,840
2,840
28,946
—
2,840
—
31,786
31,786
Financial Liabilities
Trade and other payables
(3,260)
—
—
—
(3,260)
(3,260)
Interest bearing liabilities
(3,830)
(3,702)
(19,563)
(554)
(27,649)
(24,213)
(7,090)
(3,702)
(19,563)
(554)
(30,909)
(27,473)
≤
≥
Financial Assets
Cash and cash equivalents
13,826
—
—
—
13,826
13,826
Trade and other receivables
5,314
—
—
—
5,314
5,314
Other financial assets
—
—
3,053
—
3,053
3,053
19,140
—
3,053
—
22,193
22,193
Financial Liabilities
Trade and other payables
(3,009)
—
—
—
(3,009)
(3,009)
Interest bearing liabilities
(3,997)
(3,811)
(26,171)
(65)
(34,044)
(28,153)
(7,006)
(3,811)
(26,171)
(65)
(37,053)
(31,162)
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
4.6
4.2
14,985
13,826
10,000
—
—
—
24,985
13,826
Trade and other receivables
—
—
—
—
—
—
3,961
4,563
3,961
4,563
Other financial assets
0.9
0.7
—
—
528
528
2,312
2,525
2,840
3,053
Total Financial Assets
14,985
13,826
10,528
528
6,273
7,088
31,786
21,442
Financial Liabilities:
Trade and other payables
—
—
—
—
—
—
(3,260)
(3,009)
(3,260)
(3,009)
Interest bearing liabilities
10.0
9.8
(23,163)
(27,526)
(1,050)
(627)
—
—
(24,213)
(28,153)
Total Financial Liabilities
(23,163)
(27,526)
(1,050)
(627)
(3,260)
(3,009)
(27,473)
(31,162)
Net Financial Assets /
(Liabilities)
(8,178)
(13,700)
9,478
(99)
3,013
4,079
4,313
(9,720)
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.
Cash and cash equivalents
75
(75)
—
—
Interest bearing liabilities
(117)
117
—
—
Cash and cash equivalents
69
(69)
—
—
Interest bearing liabilities
(141)
141
—
—
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.
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.
2.
The Net Present Value with a 10% discount rate (NPV10) of forecasted net cash flow from the Palm Valley, Dingo and Mereenie gas
fields limited to 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)
437
281
Trade and other payables:
-
USD
(112)
(46)
-
CAD
—
(90)
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
(30)
(13)
Australian dollar -10% movement in exchange rate
36
16
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
25.00
25.00
OL3 - Palm Valley
Gas production
50.00
50.00
L7 and PL30 - Dingo
Gas production
50.00
50.00
EP 821
Oil & gas exploration
60.00
29.00
EP 105
Oil & gas exploration
60.00
60.00
EP 1121
Oil & gas exploration
45.00
35.00
EP 1251
Oil & gas exploration
30.00
24.00
EPA 111
Oil & gas exploration – application
50.00
50.00
EPA 124
Oil & gas exploration – application
50.00
50.00
ATP 2031 - Range Gas Project2
Oil & gas exploration
—
50.00
1
As announced on 20 September 2023, the farmout agreement with Peak Helium (Amadeus Basin) Pty Ltd (Peak) has been terminated. The relevant subsidiaries
have commenced the process to have ownership interests in the permits returned to pre-farmout interest, requiring the following interests to be returned to
Central:
(a) 31% in EP82, excluding Dingo Satellite Area (Central’s interest to be restored from 29% to 60%);
(b) 10% in EP112 (Central’s interest to be restored from 35% to 45%); and
(c) 6% in EP125 (Central’s interest to be restored from 24% to 30%).
2 On 30 November 2023, the Group completed the sale of its 50% interest in the Range Gas Project (ATP 2031) in Queensland’s Surat Basin by way of the sale of its
wholly owned subsidiary, Central Petroleum Eastern Pty Ltd. Refer Note 3(b).
Accounting for the Joint Arrangements is 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 are beneficial interests and 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
417
530
Trade and other receivables
3,212
3,412
Inventory
3,406
3,161
Total current assets
7,035
7,103
Non-current assets
Property, plant and equipment
47,543
51,173
Right of use assets
387
88
Total non-current assets
47,930
51,261
Current liabilities
Trade and other payables
3,038
2,834
Lease liabilities
10
32
Deferred revenue
1,087
1,371
Provision for production over-lift
871
862
Restoration provision
299
300
Total current liabilities
5,305
5,399
Non-current liabilities
Deferred revenue
10,237
11,632
Lease liabilities
396
68
Provision for production over-lift
738
1,594
Restoration provision
19,018
19,885
Total non-current liabilities
30,389
33,179
Net assets
19,271
19,786
Joint arrangement contribution to profit before tax
Revenue
37,154
39,255
Other income
77
72
Expenses
(25,266)
(34,629)
Profit before income tax
11,965
4,698
In July 2024, new Gas Sale Agreements were executed and are expected to provide more reliable cash flows for Central from 1 January
2025, benefitting from higher average contracted gas prices and more consistent, firm sales that will not be affected by interruptions to the
Northern Gas Pipeline.
No matters or circumstances have arisen between 30 June 2024 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.
This consolidated entity disclosure statement (CEDS) has been prepared in accordance with the Corporations Act 2001 and includes
information for each entity that was part of the consolidated entity as at the end of the financial year in accordance with AASB 10
Consolidated Financial Statements
NAME OF ENTITY
TYPE OF ENTITY
TRUSTEE,
PARTNER OR
PARTICIPANT
IN JV
% OF SHARE
CAPITAL
PLACE OF BUSINESS
/ COUNTRY OF
INCORPORATION
AUSTRALIAN
RESIDENT
OR FOREIGN
RESIDENT
Central Petroleum Limited
Body corporate
–
100
Australia
Australian
Merlin Energy Pty Ltd1
Body corporate
–
100
Australia
Australian
Central Petroleum Projects Pty Ltd
Body corporate
–
100
Australia
Australian
Helium Australia Pty Ltd1
Body corporate
–
100
Australia
Australian
Ordiv Petroleum Pty Ltd1
Body corporate
–
100
Australia
Australian
Frontier Oil & Gas Pty Ltd1
Body corporate
–
100
Australia
Australian
Central Geothermal Pty Ltd
Body corporate
–
100
Australia
Australian
Central Petroleum Services Pty Ltd
Body corporate
–
100
Australia
Australian
Central Petroleum PVD Pty Ltd
Body corporate
–
100
Australia
Australian
Central Petroleum (NT) Pty Ltd1
Body corporate
–
100
Australia
Australian
Jarl Pty Ltd
Body corporate
–
100
Australia
Australian
Central Petroleum Mereenie Pty Ltd
Body corporate
Trustee
100
Australia
Australian
Central Petroleum Mereenie Unit Trust1
Trust
–
100
Australia
Australian
Central Petroleum WS (NO 1) Pty Ltd
Body corporate
–
100
Australia
Australian
Central Petroleum WS (NO 2) Pty Ltd
Body corporate
–
100
Australia
Australian
1 These entities are participants in unincorporated joint ventures with third parties not included within the consolidated entity.
1. In the Directors’ opinion:
a) the financial statements and notes set out on pages 46 to 91 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 2024 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;
c) the consolidated entity disclosure statement on page 92 is true and correct; and
d) 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 2024.
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
18 September 2024
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 2024 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 financial report comprises:
the consolidated balance sheet as at 30 June 2024
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, including material accounting policy
information and other explanatory information
the consolidated entity disclosure statement as at 30 June 2024
the directors’ declaration.
Basis for opinion
We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under
those standards are further described in the Auditor’s responsibilities for the audit of the financial
report section of our report.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis
for our opinion.
Independence
We are independent of the Group in accordance with the auditor independence requirements of the
Corporations Act 2001 and the ethical requirements of the Accounting Professional & Ethical
Standards Board’s APES 110 Code of Ethics for Professional Accountants (including Independence
Standards) (the Code) that are relevant to our audit of the financial report in Australia. We have also
fulfilled our other ethical responsibilities in accordance with the Code.
PricewaterhouseCoopers, ABN 52 780 433 757
480 Queen Street, BRISBANE QLD 4000, GPO Box 150, BRISBANE QLD 4001
T: +61 7 3257 5000, F: +61 7 3257 5999
Liability limited by a scheme approved under Professional Standards Legislation
Our audit approach
An audit is designed to provide reasonable assurance about whether the financial report is free from
material misstatement. Misstatements may arise due to fraud or error. They are considered material if
individually or in aggregate, they could reasonably be expected to influence the economic decisions of
users taken on the basis of the financial report.
We tailored the scope of our audit to ensure that we performed enough work to be able to give an
opinion on the financial report as a whole, taking into account the geographic and management
structure of the Group, its accounting processes and controls and the industry in which it operates.
Audit scope
Key audit matters
Our audit focused on where the Group made
subjective judgements; for example, significant
accounting estimates involving assumptions and
inherently uncertain future events.
Amongst other relevant topics, we communicated
the following key audit matters to the Audit and
Financial Risk Committee:
o
Basis of Preparation of the financial
report; and
o
Valuation of exploration and
evaluation assets.
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.
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
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
continuity of normal business activities and the
realisation of assets and settlement of 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
In assessing the appropriateness of the Group’s going
concern basis of preparation for the financial report, we
performed the following procedures, amongst others:
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.
evaluated the Group’s plans for future actions
(including alternative options in relation to the
current exploration permits), and whether they
Key audit matter
How our audit addressed the key audit matter
options 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).
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 projected debt
compliance over the forecast period.
evaluated whether, in view of the
requirements of Australian Accounting
Standards, the financial report provides
adequate disclosures about these events or
conditions.
Valuation of exploration and evaluation assets
($7,674,000)
Refer to note 12 of the financial report and Note 1 (p)
The Group assesses the recoverability of the carrying
value of capitalised exploration and evaluation assets
at each reporting date (or during the year should the
need arise). In completing this assessment, regard is
given to the currency of the right of tenure over the
area of interest, the Group's intentions with respect to
proposed future exploration and development plans for
the area of interest, and to the success or otherwise of
activities undertaken in the area of interest. Exploration
and evaluation activities that have not yet reached a
stage that permits reasonable assessment of the
existence of economically recoverable reserves may be
subject to impairment in the future.
The Group concluded that there was an impairment
indicator, and recognised an associated impairment
expense for the Palm Valley Deep prospect of $325k.
We considered management’s indicator assessment to
be a key audit matter given the significance of the
assets to the consolidated balance sheet and the
uncertainty surrounding the sub-salt exploration
program.
To evaluate the Group’s assessment of whether any
indicators of impairment exist, we performed the
following procedures, amongst others:
inquired with key operational and finance staff
to develop an understanding of the current
status and future intention for each area of
interest.
obtained and read relevant support including
internal and external documents for current
and future intentions for each area of interest.
considered that areas of interest that remain
capitalised are included in future budgets
and/or operational plans of the Group.
ascertained licence expiry dates of the areas
of interest to assess whether there were any
areas where the Group’s right to explore is
either at, or close to, expiry.
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 2024, 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 in accordance
with Australian Accounting Standards and the Corporations Act 2001 , including giving a true and fair
view, and for such internal control as the directors determine is necessary to enable the preparation of
the financial report that 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 the directors’ report for the year ended 30 June
2024.
In our opinion, the remuneration report of Central Petroleum Limited for the year ended 30 June 2024
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
Brisbane
Partner
18 September 2024
The 20 largest registered holders of the quoted securities as at 13 September 2024 were:
1
Norfolk Enchants Pty Ltd
48,594,871
6.57
2
Moranbah Nominees Pty Ltd
19,526,612
2.64
3
Brazil Farming Pty Ltd
17,785,209
2.40
4
Citicorp Nominees Pty Limited
16,020,177
2.16
5
Maitri Pty Ltd
15,180,139
2.05
6
Mr Peter Vrettos
14,867,172
2.01
7
Mr Kenneth John Beer + Mr Alexander Charles Beer
14,840,846
2.01
8
Macquarie Bank Limited
14,166,667
1.91
9
JH Nominees Australia Pty Ltd
12,842,031
1.74
10
Mr Philip Gasteen
12,373,780
1.67
11
Chembank Pty Limited
10,000,000
1.35
12
Kensington Capital Partners Pty Ltd
8,000,000
1.08
13
ITA Vero Pty Ltd
7,000,000
0.95
14-16 Justwright Investments Pty Ltd
7,000,000
0.95
14-16 PA and RE Gibson Pty Ltd
7,000,000
0.95
17
BNP Paribas Nominees Pty Ltd
6,514,229
0.88
18
Chembank Pty Limited
6,000,000
0.81
19
Mr Donald Leonard Cottee
5,830,594
0.79
20
Ms Dian Paramita
5,127,400
0.69
Total 256,140,576
34.61
A distribution schedule of the number of holders in each class of equity securities as at 13 September 2024 was:
1 – 1,000
121
-
1,001 – 5,000
244
-
5,001 – 10,000
446
3
10,001 – 100,000
2,093
62
100,001 – Over
819
8
Total
3,723
73
At 13 September 2024, there were 17,992,427 unlisted share rights on issue.
Substantial shareholders as disclosed by notices received by the Company as at 13 September 2024 with holdings of 5% or more of the
total votes attached to the voting shares or interests in the Entity:
Troy Harry
66,736,902
Holdings less than a marketable parcel of ordinary shares (being 10,417 shares as at 13 September 2024):
828
4,939,389
Subject to any rights or restrictions for the time being attached to any class or classes of shares, at meetings of shareholders or classes of
shareholders:
•
each shareholder entitled to vote may vote in person or by proxy, attorney or representative of a shareholder;
•
on a show of hands, every person present who is a shareholder or a proxy, attorney or representative of a shareholder has one
vote; and
•
on a poll, every person present who is a shareholder shall, in respect of each fully paid share held by him, or in respect of which he
is appointed a proxy, attorney or representative, have one vote for their share, but in respect of partly paid shares, shall have such
number of votes being equivalent to the proportion which the amount paid (not credited) is of the total amounts paid and payable
in respect of those shares (excluding amounts credited).
There is no current on-market buy-back of the Company’s securities.
Central Petroleum Limited and its Board are committed to achieving and demonstrating high standards of corporate governance. The
Company has reviewed its corporate governance practices against the Corporate Governance Principles and Recommendations (4th edition)
published by the ASX Corporate Governance Council.
The 2024 Corporate Governance Statement reflects the corporate governance practices in place throughout the 2024 financial year. The
Company’s Corporate Governance Statement undergoes periodic review by the Board. A description of the Group’s current corporate
governance practices is set out in the Group’s Corporate Governance Statement which can be viewed at
www.centralpetroleum.com.au/about/corporate-governance/.
EP82 (excl. EP82 Sub-Blocks) 1(a) Amadeus Basin NT
Santos
29
60
Santos QNT Pty Ltd (“Santos”)
40
EP82 Sub-Blocks
Amadeus Basin NT
Central
100
100
EP105
Amadeus/Pedirka Basin NT
Santos
60
60
Santos
40
EP112 1(b)
Amadeus Basin NT
Santos
35
45
Santos
55
EP115
Amadeus Basin NT
Central
100
100
EP1251(c)
Amadeus Basin NT
Santos
24
30
Santos
70
OL3 (Palm Valley)
Amadeus Basin NT
Central
50
50
Echelon Palm Valley Pty Ltd
Cue Palm Valley Pty Ltd
35
15
OL4 (Mereenie)
Amadeus Basin NT
Central
25
25
Echelon Mereenie Pty Ltd
Horizon Australia Energy Pty Ltd
Cue Mereenie Pty Ltd
42.5
25
7.5
OL5 (Mereenie)
Amadeus Basin NT
Central
25
25
Echelon Mereenie Pty Ltd
Horizon Australia Energy Pty Ltd
Cue Mereenie Pty Ltd
42.5
25
7.5
L6 (Surprise)
Amadeus Basin NT
Central
100
100
L7 (Dingo)
Amadeus Basin NT
Central
50
50
Echelon Dingo Pty Ltd
Cue Dingo Pty Ltd
35
15
RL3 (Ooraminna)
Amadeus Basin NT
Central
100
100
RL4 (Ooraminna)
Amadeus Basin NT
Central
100
100
ATP9092
Georgina Basin QLD
Central
100
100
ATP9112
Georgina Basin QLD
Central
100
100
ATP9122
Georgina Basin QLD
Central
100
100
EPA92
Wiso Basin NT
Central
100
100
EPA1113
Amadeus Basin NT
Santos
50
50
Santos
50
EPA124 4
Amadeus Basin NT
Santos
50
50
Santos
50
EPA129
Wiso Basin NT
Central
100
100
EPA130
Pedirka Basin NT
Central
100
100
EPA132
Georgina Basin NT
Central
100
100
EPA133
Amadeus Basin NT
Central
100
100
EPA137
Amadeus Basin NT
Central
100
100
EPA147
Amadeus Basin NT
Central
100
100
EPA149
Amadeus Basin NT
Central
100
100
EPA152 4
Amadeus Basin NT
Central
100
100
EPA160
Wiso Basin NT
Central
100
100
EPA296
Wiso Basin NT
Central
100
100
PL2
Amadeus Basin NT
Central
25
25
Echelon Mereenie Pty Ltd
Horizon Australia Energy Pty Ltd
Cue Mereenie Pty Ltd
42.5
25.0
7.5
PL30
Amadeus Basin NT
Central
50
50
Echelon Dingo Pty Ltd
Cue Dingo Pty Ltd
35
15
Notes:
1 The farmout agreement with Peak Helium (Amadeus Basin) Pty Ltd (Peak) has been terminated and the relevant subsidiaries have commenced the
process to have ownership interests in the permits returned to pre-farmout interest, requiring the following interest to be returned to Central:
(a)
31% in EP82, excluding Dingo Satellite Area (Central’s interest changed from 29% to 60%)
(b)
10% in EP112 (Central’s interest changed from 35% to 45%); and
(c)
6% in EP125 (Central’s interest changed from 24% to 30%)
2 Central intends to surrender its interests in the Georgina Basin (Qld permits ATP 909, ATP 911 and ATP 912). On 10 January 2023, Central submitted a
relinquishment notice for ATP911. On 13 March 2023, a work program amendment was approved for ATP909 & ATP912 which includes only the
abandonment of existing wells ahead of relinquishment.
3 On 16 December 2021 Central received notice from the NT Department of Industry Tourism and Trade (DITT) that EPA111 had been placed in moratorium
for a period of 5 years from 9 December 2021 until 9 December 2026.
4 On 22 March 2018 (in respect of EPA124) and on 23 March 2018 (in respect of EPA152) Central received notice from DITT that EPA124 and EPA152, as
applicable, had been placed in moratorium on 6 December 2017 for a five year period which ended on 6 December 2022. On 12 April 2023, Central was
provided with consent to negotiate the grant of EPA152.
1P
Proved reserves*
2C
Best estimate contingent resources*
2P
Proved and probable reserves*
Bbl
barrel of oil (unit of measure)
Bcf
billion cubic feet
Bopd
barrel of oil per day
EBIT
Earnings before interest and tax
EBITDA
Earnings before interest, tax, depreciation, amortisation and impairment
EBITDAX
Earnings before interest, tax, depreciation, amortisation and exploration costs
EIP
Executive incentive plan
ESOP
Executive share option plan
GJ
Gigajoule (1 billion joules) (unit of energy measure)
GJe
Gigajoule equivalent (oil converted at 5.816 GJe / bbl)
GSA
Gas sale agreement
IFRS
International Financial Reporting Standards
KMP
Key management personnel
KPI
Key performance indicator
LTIP
Long term incentive plan
Mcfd
Thousand cubic feet per day
mmbl
Million barrels
PJ
Petajoules (1,000 TJ) (unit of energy measure)
PJe
Petajoule equivalent (oil converted at 5.816 PJe / mmbbl)
scfd
Standard cubic feet per day
STIP
Short term incentive plan
TFR
Total fixed remuneration
TJ
Terajoule (1,000 GJ) (unit of energy measure)
TJ/d
Terajoules per day
Tcf
Trillion cubic feet (unit of measure)
* As defined by Petroleum Resources Management System (PRMS) 2018 published by the Society of Petroleum Engineers.
ABN 72 083 254 308
Mr Michael (Mick) McCormack BSurv, GradDipEng, MBA, FAICD, Independent Non-Executive Director, Chair
Mr Leon Devaney BSc MBA, Managing Director and Chief Executive Officer
Mr Stephen Gardiner BEc (Hons), Fellow - CPA Australia, Independent Non-Executive Director
Ms Katherine Hirschfeld AM, BE(Chem) HonDEng, HonFIEAust, FTSE, FIChemE, FAICD, Independent Non-Executive Director
Dr Agu Kantsler BSc (Hons), PhD, GAICD, FTSE, Independent Non-Executive Director
Mr Daniel White LLB, BCom, LLM
Level 7, 369 Ann Street, Brisbane, Queensland 4000
Telephone:
+61 7 3181 3800
Facsimile:
+61 7 3181 3855
www.centralpetroleum.com.au
PricewaterhouseCoopers
480 Queen Street, Brisbane, Queensland 4000
Computershare Investor Services Pty Limited
Level 1, 200 Mary Street, Brisbane, Queensland 4000
Telephone:
1300 552 270
Telephone:
+61 3 9415 4000
Facsimile:
+61 3 9473 2500
www.computershare.com.au
Central Petroleum Limited shares are listed on the Australian Securities Exchange under the code CTP.
Head Office
Level 7, 369 Ann Street, Brisbane, Qld 4000
Postal Address
GPO Box 292, Brisbane, Qld 4000
Email: info@centralpetroleum.com.au
www.centralpetroleum.com.au