(cid:21)(cid:19)
(cid:21)(cid:19)
(cid:36) (cid:49) (cid:49) (cid:56) (cid:36) (cid:47) (cid:53) (cid:40) (cid:51) (cid:50) (cid:53) (cid:55)
(cid:38)(cid:72)(cid:81)(cid:87)(cid:85)(cid:68)(cid:79) (cid:51)(cid:72)(cid:87)(cid:85)(cid:82)(cid:79)(cid:72)(cid:88)(cid:80) (cid:47)(cid:76)(cid:80)(cid:76)(cid:87)(cid:72)(cid:71)
(cid:36)(cid:38)(cid:49) (cid:19)(cid:27)(cid:22) (cid:21)(cid:24)(cid:23) (cid:22)(cid:19)(cid:27)
TABLE OF CONTENTS
CHAIRMAN’S LETTER .............................................................................................................................................................. 1
CHIEF EXECUTIVE OFFICER’S LETTER .......................................................................................................................... 2
OPERATING AND FINANCIAL REVIEW .......................................................................................................................... 3
DIRECTORS’ REPORT ........................................................................................................................................................... 23
EXECUTIVE SUMMARY – REMUNERATION ................................................................................................................. 29
REMUNERATION REPORT ................................................................................................................................................. 30
AUDITOR’S INDEPENDENCE DECLARATION ............................................................................................................ 44
FINANCIAL REPORT ............................................................................................................................................................ 45
CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME ........... 46
CONSOLIDATED BALANCE SHEET ................................................................................................................................ 47
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY ...................................................................................... 48
CONSOLIDATED STATEMENT OF CASH FLOWS ..................................................................................................... 49
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS .............................................................................. 50
DIRECTORS’ DECLARATION ............................................................................................................................................. 95
INDEPENDENT AUDITOR’S REPORT ............................................................................................................................ 96
ASX ADDITIONAL INFORMATION ................................................................................................................................. 103
CORPORATE GOVERNANCE STATEMENT ................................................................................................................ 104
INTERESTS IN PETROLEUM PERMITS AND PIPELINE LICENCES AT THE DATE OF THIS REPORT ... 105
CORPORATE DIRECTORY ................................................................................................................................................ 107
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.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
CHAIRMAN’S LETTER
Dear Fellow Shareholders
At the Annual General Meeting in November last year, no one
could have predicted within the next quarter, the world and all
our lives would become so seriously impacted by a global
pandemic. This year has highlighted the importance of having
the stability, financial strength and flexibility to be able to ride-
out the downturn and recession caused by the pandemic, while
having the capability to capitalise on the opportunities that
inevitably arise.
Just a few years ago, Central’s circumstances would have
required drastic action to ride-out today’s conditions. However, I
am pleased today’s Central has a new resilience built on a strong
portfolio of producing gas fields, backed by long-term, fixed-
price gas sales contracts.
The market disruption may have taken some gloss from the
annual results, but the underlying numbers can’t be ignored.
This year we have recorded our first full year profit after tax,
posted record sales volumes and revenues, and upgraded our
booked reserves.
This outcome is the culmination of strategic positioning and
successful execution to expand production capacity to take
advantage of new access to eastern markets through the
Northern Gas Pipeline (NGP) which was commissioned in
January 2019.
We are excited by the recently announced proposal to construct
the Amadeus to Moomba Gas Pipeline (AMGP). The AMGP is a
shorter, more direct route, with fewer bottlenecks to deliver our
gas to the increasingly short southern markets and should result
in increased sales volumes and higher margins for Central.
Oil and gas has been produced from the Amadeus Basin for
decades, but its potential has been limited by distance to
market. Completion of the AMGP, a second pipeline connection
to the east within 5 years of the NGP, would be a ‘game-
changer’ for Central, providing a catalyst for the Amadeus Basin
to become an increasingly important part of the solution for
south-eastern Australia’s looming gas shortage.
It is easy to be distracted by the current weakness in gas spot
prices, but forecasts indicate southern Australia will see a major
and continuing shortage of gas from 2023 as gas supplies
continue to decline from the 50-year old Bass Strait fields,
exacerbated by the planned closure of coal-fired power stations,
such as the Liddell Power Station in NSW. Central’s next phase
of growth will target this market supply opportunity.
A successful return to the much-anticipated Dukas well in 2022
could also provide a huge new resource for southern markets
and we are already working on other large potential sub-salt
leads in the basin. In Queensland, we added 135 PJ of 2C
contingent resource at our Range Gas Project and are aiming to
reach a final investment decision next year, with first gas
production targeted for 2023.
The value of our producing assets and growth potential is clear,
and our challenge now is to deliver a successful exploration
programme in 2021, followed by a Final Investment Decision
(FID) for the Range Gas Project and the AMGP. At the same
time, we will continue to build on the relationships we have
established with our valued stakeholders. As a proud Australian
company, we are continuing to deliver on our ‘buy local and
employ local’ policy to provide employment and business
opportunities to the local communities and Traditional Owners
in the areas where we operate.
There has been continuing discussion about the gas growth
story and the role natural gas can play as global economies
transition from coal to renewable energy sources. It is clear that
gas has an important role to play in reducing emissions while
maintaining the stability and reliability of energy generation.
Australia’s Chief Scientist, Alan Finkle has stated that Australia’s
electricity supply will remain dependent on “complementary”
gas power for up to 30 years as the nation’s grids make the
transition to zero emissions renewable energy. Consistent with
the Federal Government’s recently announced Energy Plan, our
continuing investment in exploration and growth projects and
commitment to pipeline infrastructure can assist in this
transition process.
Environmental impacts from our operations in the Amadeus
Basin remain relatively small. We do not extract and discharge
CO2 due to the extremely low levels contained in our produced
gas. We use proven conventional drilling techniques to extract
our gas and our planned development and exploration
programmes do not require fracking.
Our strategy for success includes building a team with the right
balance of skills, experience and vision to deliver on our plans.
Importantly we have added two very experienced professionals
to our Board in recent months—former Woodside Executive
Vice President of Exploration, Dr Agu Kantsler and former APA
Group MD, Mick McCormack. Agu and Mick bring many years of
industry experience to the Board and share our confidence in
our business and growth strategy.
Our good news story for this year has been our resilience in the
face of the global pandemic. For FY2021, we aim to build upon
our established production base through a mix of continuing
field development and high impact exploration.
With the successful delivery of these exciting growth projects, I
am confident that the value of our impressive asset portfolio in
the Northern Territory and Queensland will become more
widely recognised.
In conclusion, I wish to thank the Traditional Owners of the land
on which we operate and to thank all our shareholders for your
support of your Board and management as we continue to
progress through these challenging times.
Thank you,
Wrixon Gasteen, Chairman
24 September 2020
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
1
CHIEF EXECUTIVE OFFICER’S LETTER
Dear Fellow Shareholders
Since last year’s Annual Report CEO Letter, we have seen some
very challenging business conditions. Throughout this turbulence,
I have been buoyed by the underlying resilience and stability of
Central Petroleum’s producing assets and people, which has us
well-placed to launch into a substantial new phase of growth.
FY2020 has been a year of two halves. The first half saw good
momentum with:
•
continuing high gas and oil production from our recently
upgraded fields in the Northern Territory
•
•
•
a successful Range exploration programme delivering 135 PJ
of new 2C gas resources in the Surat Basin
positive indicators of hydrocarbon-bearing gas from an over-
pressurised zone at the much-anticipated, but now
suspended, Dukas-1 exploration well
announcement of a major new Amadeus Basin exploration
programme that has Company-changing potential.
The second half turned into an uphill climb very quickly, with a
severe downturn in global energy markets and heightened
business uncertainty as COVID-19 emerged into a pandemic. This
tested our resilience and flexibility and, in so doing, highlighted an
often-unrecognised pillar of our business strategy: stronger
financial foundations through quality operating assets that protect
shareholder value through downturns.
Although the full-year financial results for FY2020 were impacted
by the energy market downturn, it was still a record year for sales
volumes for Central, which were up 14% to 12.3 PJE generating
revenue of $65M. Our earnings before interest, tax, depreciation,
amortisation and exploration (EBITDAX) were $33 million, up 51%
on FY2019 and easily covering (2.0x) service of loan facilities of
$16.4M, which included accelerated principal repayments of
$11.5M. Importantly, our portfolio of fixed-price, long-term gas
supply contracts have provided sufficient cash flow after debt
service to cover our operating and corporate costs.
There were a number of other business highlights, including:
•
16% increase in 2P reserves
•
12-month extension to our finance facilities
• maintained a strong cash balance of $26M
•
reached JV agreement on a forward plan for the multi-Tcf
Dukas prospect.
Our planned exploration programme in the Amadeus Basin is a
great opportunity for Central to quickly accelerate production by
targeting formations known to be productive in other areas and
located in or near existing producing fields and infrastructure.
While we have a seriatim of attractive exploration targets, our
immediate focus is to drill three exploration wells next year
targeting circa 600 PJ of mean prospective resources.
Our Range Gas Project in Queensland’s Surat Basin is another key
part of Central’s growth strategy, with 135 PJ (net to Central) of
‘development-pending’ 2C contingent gas resources, anticipated
to have significant value as a future source of east coast gas
supply. After pausing activity earlier this year, we are seeking to
restart Range pre-FID activity as quickly as possible in an effort to
achieve FID in late 2021 (with potential to nearly double our 2P
reserves) and target first gas in late 2023 (nearly doubling current
gas sales).
2
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
As part of our forward plan for Dukas, we are now working with
our JV partner Santos to recommence drilling in 2022. There
remains enormous upside in the large, yet underexplored
Amadeus Basin, and a return to the multi-Tcf Dukas prospect and
future exploration at another large sub-salt lead (Zevon) in EP115
are both opportunities to find major new multi-Tcf gas supply for
the east coast domestic market.
Our growth strategy is bold and positioned to take full advantage
of what I believe will be a strong recovery in the domestic gas
market from 2022. But our vision for where Central can go from
here should be even more exciting for shareholders. Until only
recently, the Amadeus Basin was remote, isolated and generally
‘flew under the radar’. It is now becoming recognised as one of
the best onshore opportunities to deliver material new gas
supplies to the east coast market, with decades of proven gas
production, significant existing 2P reserves and massive
conventional and unconventional prospective resources.
Whilst commencement of the Northern Gas Pipeline last year was
a catalyst for increased activity in the Amadeus Basin, we recently
entered into an MOU to progress the Amadeus to Moomba Gas
Pipeline (AMGP) with Macquarie Mereenie and Australian Gas
Infrastructure Group (AGIG). The AMGP more than halves the
distance that our gas would travel to Moomba, with the prospect
of significantly lower tariffs. This would open up a major new cost-
efficient gas supply from the Amadeus Basin for the southern east
coast market, which will be increasingly short on gas.
Funding Company-changing growth strategies remains a key
focus, particularly given the scope of activity relative to our size
and the current weak market conditions. We have been actively
pursuing a range of alternatives and, as we have done in the past,
our funding strategy will seek to maximise shareholder value. The
current process for a partial sell-down of our existing Amadeus
Basin assets continues to be encouraging, with interest
reinvigorated following recent announcements on the AMGP and
the Federal Government’s Energy Plan. Given the significance of a
partial sell-down, it is critical that we don’t rush, but instead take
the time necessary to get the best outcome with the right partner.
I would like to take this opportunity to thank our dedicated staff
for safely, effectively and efficiently operating our business
throughout the year. A number of our field personnel spent
extended periods away from family and friends to keep our fields
operating through the COVID-19 border closures. Their efforts and
dedication are at the heart of Central’s successes.
I also wish to thank our many stakeholders for their continued
support during a very challenging year. As the past year has clearly
demonstrated, challenges and opportunities are both part of this
business. With our strong Board, experienced management and
dedicated employees, I have every confidence that our growth
strategies will be delivered, and their value recognised in the
market.
Leon Devaney, CEO
24 September 2020
OPERATING AND FINANCIAL REVIEW
OPERATING HIGHLIGHTS
•
•
Record annual sales volumes and revenues:
o Volumes up 14% to 12.3 PJE
o
Revenues up 10% to $65 million.
51% increase in EBITDAX to $33.4 million.
• Maiden full year profit of $5.4 million.
•
•
•
•
•
•
•
16% increase in 2P reserves to 161.2 PJE.
Added 135 PJ of 2C contingent gas reserves (Central share) at the Range Gas Project in the Surat Basin after completion of a
successful four well exploration programme.
Dukas-1 well was suspended after encountering hydrocarbon-bearing gas from an over-pressured zone close to the primary
target and a forward plan to complete the Dukas exploration programme is now underway.
Excellent safety record with no MTIs or LTIs during the year.
Reduced net debt by 30% to $46.1 million and extended loan facility by 12 months to late 2021.
Strengthened the Board with the appointment of Dr Agu Kantsler and Mr Mick McCormack, both highly respected industry
leaders with proven experience in the core areas critical to Central’s future success.
Subsequent to the year end, announced an MOU with highly capable partners, Macquarie Mereenie and Australian Gas
Infrastructure Group (AGIG), to progress towards a final investment decision on a proposed major new pipeline to enable
Central’s gas to be transported direct to the Moomba gas supply hub and the larger south-eastern Australian gas markets with
significantly greater cost efficiencies.
EBITDAX: Increased 51% to $33.4m in FY2020
(Earnings before interest, tax, depreciation, impairment and exploration costs)
Operating revenue: Increased 10% to $65m in FY2020
Reserves & Resources: 2P reserves up 16% to 161.2 PJE and 135 PJ of 2C
resources added
Net Debt: decreased by 30% to $46.1 million at 30 June 2020
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
3
OPERATING AND FINANCIAL REVIEW
FINANCIAL REVIEW
The Consolidated Entity had a profit after income tax for the year ended 30 June 2020 of $5.4 million (2019: loss of $14.5 million).
The above result was after expensing exploration costs of $5.3 million (2019: $15.8 million). The Group’s policy is to expense all exploration
costs as incurred.
The table below shows key metrics for the Group:
Change
% Change
16%
(9)%
10%
9%
51%
341%
N/A
N/A
538%
(82)%
2019
$’000
(14,526)
8,215
(6,311)
12,695
—
6,384
15,802
22,186
Key Metrics
Net Sales Volumes
-
-
Natural Gas (TJ)
Oil & Condensate (bbls)
Sales Revenue ($‘000)
Gross Profit ($‘000)
EBITDAX1 ($‘000)
EBITDA2 ($’000)
EBIT3 ($‘000)
Statutory profit/(loss) after tax ($‘000)
Net cash inflow from Operations4 ($’000)
Capital expenditure5 ($‘000)
Total
2020
11,822
89,016
65,046
31,660
33,403
28,126
11,692
5,411
15,727
2,857
Total
2019
10,229
97,392
59,358
28,989
22,186
6,384
(6,312)
(14,526)
2,465
16,188
1,593
(8,376)
5,688
2,671
11,217
21,742
18,004
19,937
13,262
(13,331)
1 EBITDAX is Earnings before Interest, Tax, Depreciation, Amortisation, Impairment and Exploration costs (refer reconciliation below).
2 EBITDA is Earnings before Interest, Tax, Depreciation, Amortisation and Impairment.
3 EBIT is Earnings before Interest and Taxation.
4 Cashflow from Operations includes cash outflows associated with Exploration activities.
5 Capital expenditure on tangible assets.
Reconciliation of statutory profit/(loss) before tax to EBITDAX
Statutory profit/(loss) before tax
Net finance costs
EBIT
Depreciation and amortisation
Impairment
EBITDA
Exploration expenses
EBITDAX
2020
$’000
5,411
6,281
11,692
16,257
177
28,126
5,277
33,403
4
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
Sales Volumes
Sales volumes were 14% higher than FY2019 at 12.34 PJE, reflecting the first full financial year to benefit from the new Northern Gas
Pipeline (NGP) and the newly commissioned, high-performing PV13 well at Palm Valley.
Note: Oil converted at 5.816 GJ/bbl.
Sales volumes in the 2nd half of FY2020 were market-constrained due to the significant downturn in spot market conditions, largely
reflecting the Company’s portfolio of firm long-term gas supply contracts which have various terms that extend into the future as
illustrated below.
Sales Revenue
Central recorded record-high sales revenue of $65 million, up 10% on FY2019, and almost double the revenue recognised in FY2018,
reflecting the increased field capacity and increased gas volumes sold through the NGP. Realised oil prices were down 31% on FY2019, as a
result of global oil price weakness.
Gross Profit
Gross profit from operations increased 9% year on year, benefiting from a 5% drop in unit production costs to $2.71/GJE as increased
production levels provided increased economies of scale and strategies to manage costs continued to deliver cost-effective operations.
Other Income
Other income of $8.6 million was received during the year, including $7.7 million as final settlement for the transfer of a 50% interest in the
Range Gas Project and $0.68 million profit on the transfer of exploration tenements.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
5
OPERATING AND FINANCIAL REVIEW
Depreciation and Amortisation
Non-cash depreciation and amortisation costs increased from $12.7 million to $16.3 million, reflecting the increase in production and
larger depreciable asset base following the Gas Acceleration Programme (GAP).
An impairment charge of $0.177 million was recognised for legacy costs associated with less-prospective exploration areas.
Net Assets/Liabilities
At 30 June 2020, the Group had a net asset position of $1.6 million, an improvement on FY2019 due to the net profit for the year.
Included in liabilities on the Group’s balance sheet are amounts recognised in respect of deferred revenue associated with pre-sales and
make-up gas provisions amounting to $33.8 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.
Debt
Net debt improved by 30% to $46.1 million at 30 June 2020. EBITDAX of $33.4 million covered (2.0x) service of loan facilities of
$16.4 million, which included accelerated loan repayments of $11.5 million. This included full repayment of the balance of additional funds
previously borrowed for our investment in the GAP. The outstanding balance of the loan facility at 30 June 2020 was $70.8 million, with
$7.0 million due for repayment in FY2021.
The consolidated debt ratio at 30 June 2020 improved to 0.45 (2019: 0.49). Debt ratio is defined as: Total Debt/Total Assets. Net gearing at
30 June 2020 was 44% (2019: 40% or 53% if re-based to 30 June 2020 market capitalisation). Net gearing is calculated as: Net Debt /
(Market capitalisation + Net Debt). Debt service is supported by long term gas sales contracts and the Group’s certified 2P reserves.
Net Cash Flow
Cash balances increased by $8.1 million over the year. Net cash flow from production operations for 2020 was $29.0 million compared to
$31.8 million for 2019 and is net of additional gas purchases of $5.3 million associated with reducing the gas overlift position from the
Mereenie joint venture.
After payment of $5.1 million of interest costs, $5.1 million of corporate expenses and $3.1 million for exploration activities, net cash flow
from operating activities was $15.7 million, up from $2.5 million in 2019. Exploration expenditure in FY2020 was significantly lower than
the $18.1 million outlaid in FY2019 on activities that included the successful Palm Valley 13 exploration well.
The net cash surplus from operating activities was directed towards $11.5 million of borrowing repayments and $3.2 million was invested
in sustaining capital works. Cash balances were boosted with the receipt of $7.7 million as final settlement for the transfer of a 50%
interest in the Range Gas Project.
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.
2016
$ MILLION
2017
$ MILLION
2018
$ MILLION
2019
$ MILLION
2020
$ MILLION
Financial Data
Operating revenue
Exploration expenditure
Profit/(loss) after income tax
EBITDAX
Equity issued during year
Property, plant and equipment
Cash
Borrowings
Net Assets (Total Equity)
Net Working Capital (Net current assets/(liabilities))
23.86
4.03
(21.04)
2.58
11.52
113.78
15.12
(85.70)
16.52
5.33
24.79
1.90
(24.73)
2.22
.—
106.82
5.48
(82.17)
(5.96)
0.73
34.94
8.79
(14.08)
11.01
25.47
103.85
27.22
(78.33)
7.06
17.19
59.36
15.80
(14.53)
22.19
.—
123.48
17.81
(81.73)
(5.62)
(1.53)
65.05
5.28
5.41
33.40
.—
107.85
25.92
(70.77)
1.58
6.75
Operating Data
Gas Sales (TJ)
Oil Sales (barrels)
No. of employees at 30 June
2016
2017
2018
2019
2020
3,230
98,635
83
3,322
111,380
83
4,842
105,619
89
10,229
97,392
99
11,822
89,016
92
6
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
COMMERCIAL
Amadeus to Moomba Gas Pipeline (AMGP)
In August 2020, Central and our partner in the Mereenie gas
field, Macquarie Mereenie Pty Ltd, agreed with Australian Gas
Infrastructure Group (AGIG) to progress towards a Final
Investment Decision (FID) for the development of a proposed
major new gas transmission pipeline that would provide direct
access from the Amadeus Basin in the Northern Territory (NT)
to the Moomba gas supply hub in South Australia (Moomba).
Central currently supplies gas to customers in the NT and Mt
Isa. In order for Central to sell gas into the southern parts of
the east coast market, gas would be transported over
2,200 km via Mt Isa to Moomba. The proposed AMGP would
be less than half that distance, allowing for significantly lower
gas transportation costs from the NT to the east coast via a
direct pipeline connection to Moomba which is strategically
located for supply to Sydney and the south eastern markets.
The AMGP would be developed, owned and operated by AGIG
and is planned to be a 950 km pipeline, up to 16-inch in
diameter with free-flow capacity of 124 TJ per day (45 PJ per
year) and would be expandable with compression.
The AMGP project is already well defined, having previously
completed front-end engineering and design as the subject of
a firm offer by AGIG under the North East Gas Interconnect
process conducted in 2015. The AMGP project is targeting a
FID in 2H of 2021, which could enable commencement of
construction in 2022 and deliveries of first gas in Q1 of 2024.
NT Gas Supply
Gas pipeline infrastructure and the proposed Amadeus to
Moomba Gas Pipeline (AMGP)
Central’s operated fields in the Amadeus Basin have approximately 200PJ of uncontracted conventional gas reserves (gross JV) which can
be supplied to market through the AMGP. There are also additional third-party uncontracted conventional gas reserves that could
participate as foundation volumes to supply the east coast from 2024.
Central will seek to increase production capacity from our three operated NT gas fields for delivery via the AMGP. The production capacity
can be increased by accelerating the drilling of development wells and debottlenecking or expanding existing production facilities at
Mereenie, Palm Valley and Dingo.
Aside from already established reserves, Central’s planned Amadeus Basin exploration programme to be completed in 2021 is focussed on
three high potential gas prospects, aiming to mature 593 PJ of mean prospective gas resources (100% Central). Gas discoveries resulting
from this exploration programme, as well as all of Central’s future NT exploration activity in the underexplored, but highly prospective
Amadeus Basin (such as Dukas), would directly benefit from the AMGP.
In the longer term, the AMGP could directly assist the east coast market by transporting gas from several large discovered offshore gas
fields or the various unconventional exploration programmes that are currently underway in the NT. The pipeline could also provide
efficient and highly responsive gas storage services to support growing, but intermittent, renewable energy generation.
“The implications of the AMGP project are huge, not just for Central and the NT, but for the entire east coast gas market. The AMGP is
strongly aligned with various initiatives to boost east coast gas supply as traditional supplies from Bass Strait and the Cooper Basin
decline.
What makes the AMGP stand out above other potential east coast supply proposals, is the pipeline efficiently connects significant known
conventional gas reserves from proven producing fields to east coast demand centres from 2024 which are forecast to have gas supply
shortages.”
Central’s CEO and Managing Director, Leon Devaney.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
7
OPERATING AND FINANCIAL REVIEW
OPERATIONS AND ACTIVITIES
Central Petroleum Limited is the largest onshore gas producer in the Northern Territory (NT), supplying industrial customers and senior gas
distributors in NT and the wider Australian east coast market from our three producing fields near Alice Springs.
Central is positioned to become a significant domestic energy supplier, with exploration and development plans across 180,000 km² of
tenement and application areas in Queensland and the NT, including some of Australia’s largest known onshore conventional gas
prospects. Central is also working with Australian Gas Infrastructure Group (AGIG) to progress the proposed Amadeus to Moomba Gas
Pipeline to a FID. The proposed pipeline promises to provide a more direct, cost-efficient route to eastern gas markets.
Central is also seeking to develop the Range Gas Project, a new gas field located among proven coal seam gas fields in the Surat Basin,
Queensland with 135 PJ (net to Central) of 2C contingent resource.
Producing Assets
Granted Petroleum Production and Retention Licences in which the Company has an interest
Sales Volumes (Central Petroleum’s Share)
Product
Unit
FY 2020
FY 2019
Gas
Crude and Condensate
Total
PJ
bbls
PJE
11.8
89,016
10.2
97,392
12.3
10.8
Note: Oil is converted to Petajoule equivalent (PJE) at 5.816 GJE/bbl.
Sales volumes were 14% higher than
FY2019 at 12.34 PJE, reflecting the first
full financial year to benefit from the
new Northern Gas Pipeline (NGP) and
the newly commissioned, high-
performing PV13 well at Palm Valley.
Sales volumes in the 2nd half of FY2020
were market-constrained due to the
significant downturn in spot market
conditions, largely reflecting the
Company’s portfolio of firm long-term
gas supply contracts which have various
terms that extend beyond 2025.
8
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
Mereenie Oil and Gas Field (OL4 and OL5)
Northern Territory
(CTP—50% Interest (Operator), Macquarie Mereenie Pty Ltd—50% Interest)
Sales volumes
(Central share)
Gas
Crude and Condensate
Unit
PJ
bbl
FY
2020
6.1
89,016
FY
2019
7.1
97,392
Reserves & Resources
(Central share)
Gas
Oil
Unit
PJ
mmbbl
1P
69.3
0.77
2P
91.8
0.97
2C
91.2
0.10
The Mereenie oil and gas field was discovered in 1963 and commenced production in 1984, delivering hydrocarbon liquids for sale in South
Australia and gas to Northern Territory markets. A significant expansion programme was undertaken to lift firm plant capacity to 44 TJ/d
capacity in time to supply gas to the east coast market through the Northern Gas Pipeline (NGP) in January 2019.
The Mereenie hydrocarbon accumulation is contained in an elongated 4-way dip anticline that has a length of 40 km and width of more
than 5 km. The reservoirs comprise a series of thin stacked sandstones of the Pacoota Formation, which have been the focus of
development to date. This development has targeted both gas production and oil production from an oil rim. The overlying Stairway
Sandstone has not been materially developed to date, but it represents significant upside potential as the Stairway Formation has
produced gas in several wells. Subject to JV approval, a two-well appraisal programme would be the first step in converting up to 54 PJ
(Central share) of 2C contingent gas resource to 2P reserves.
Gas production averaged 33 TJ/d over the year. During the first half of FY2020, production averaged 40 TJ/d, impacted by an extended
planned outage at the NGP. Gas production was market-constrained at an average 26 TJ/d from January due to weak spot gas markets.
Field capacity was approximately 37 TJ/day at 30 June 2020.
Updated reservoir modelling which incorporated recent strong production performance led to a 20% upgrade of the 2P gas reserves at
Mereenie, with an additional 15.8 PJ of gas and 0.19 mmbbl of oil (2P reserves, Central share) added at 30 June 2020. The reserve upgrade
was a result of a study of technical data from the elevated 2019 production levels which followed the field expansion. The results indicated
additional gas is likely to be recovered from lower permeability sands within the Mereenie reservoirs and the sales gas specification can be
maintained without the need for additional capital investment to remove Nitrogen.
To offset ongoing natural field decline, a series of minor projects were implemented during the year, including the conversion of several
injector wells into production wells.
Additional production capacity is not anticipated to be required to meet the current portfolio of firm gas contracts. Marketing continues for
new gas sale contracts and extensive planning has commenced to increase field capacity to meet this anticipated demand, including new
development wells and recompletions to access gas which is currently behind pipe in existing wells.
Mereenie Eastern Satellite Station Processing Facilities
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
9
OPERATING AND FINANCIAL REVIEW
Palm Valley Gas Field (OL3)
Northern Territory
(CTP—100% Interest)
Sales volumes
(Central share)
Gas
Unit
PJ
FY
2020
FY
2019
Reserves & Resources
(Central share)
3.9
1.9
Gas
Unit
PJ
1P
24.7
2P
27.7
2C
13.7
Gas was first discovered at Palm Valley in 1965 and is primarily reservoired in an extensive fracture system in the lower Stairway
Sandstone, Horn Valley Siltstone and Pacoota Sandstone. The anticlinal structure is approximately 29 km in length and 14 km in width. The
field was successfully restarted in 2018 in order to deliver gas into the broader gas market available via the NGP connection.
The Palm Valley field performance exceeded expectations during the year, averaging 10.8 TJ/d, more than double the FY2019 average. The
PV13 well, commissioned in May 2019, produced at a consistent 7 TJ/d throughout the year before coming off plateau in June 2020. The
continuing high production rates from this well are believed to be supported by ongoing recharge from the fracture network, indicating
further outperformance by the well remains possible.
The exceptional performance of the PV13 well led to a 26% upgrade of 2P gas reserves at Palm Valley, adding 5.8 PJ of 2P gas reserves at
30 June 2020.
Palm Valley’s existing wells are now experiencing a natural decline in production. Following the success of the PV13 well, three further
potential locations have been identified for the drilling of new lateral wells similar to PV13 in order to maintain a production plateau. It is
planned that these laterals will be drilled from existing wells and the proposed PV Deep exploration well with an expectation that future
whole-of-life unit production costs at Palm Valley will be significantly reduced.
Dingo Gas Field (L7) and Dingo Pipeline (PL30)
Northern Territory
(CTP—100% Interest)
Sales volumes
(Central share)
Gas
Unit
PJ
FY
2020
FY
2019
Reserves & Resources
(Central share)
1.2
0.9
Gas
Unit
PJ
1P
29.3
2P
36.1
2C
—
Gas was discovered at the Dingo field in 1985 in the Neoproterozoic lower Arumbera Sandstone. The structure is 11 km by 5.6 km, and the
productive reservoir is at a depth of approximately 3,000 metres subsurface.
The Dingo Gas Field supplies gas through a dedicated 50 km gas pipeline to Brewer Estate in Alice Springs for use in the Owen Springs
Power Station.
Sales volumes were 43% higher than FY2019, averaging 3.4 TJ/d with increasing demand from the power station. The daily contract volume
of 4.4 TJ/d is subject to take-or-pay provisions under which Central will be paid in January 2021 for any gas nomination shortfall by the
customer.
Surprise Oil Field (L6)
Northern Territory
(CTP—100% Interest)
The Surprise West well produced approximately 88,650 barrels of oil from March 2014 to August 2016 when it was shut in due to low oil
prices and to obtain long term pressure data.
The field remains shut in. A restart will be considered following a sufficient recovery in oil markets. Environmental and reservoir monitoring
continued throughout the year.
Range Gas Project (ATP 2031)
Surat Basin, Queensland
(CTP—50% Interest, Incitec Pivot Queensland Gas Ltd (IPL) – 50%)
Reserves & Resources
(Central share)
Gas
Unit
PJ
1P
—
2P
—
2C
135
Central was formally granted the Authority to Prospect (ATP) 2031 in Queensland’s gas-rich Surat Basin in August 2018. The Range Gas
Project’s exploration and appraisal programme is being undertaken through a 50:50 joint venture arrangement with IPL. Any gas produced
from this permit is to be dedicated to the domestic gas market.
10
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
In August 2019, Central booked a maiden 2C contingent gas resource of 270 Petajoules (PJ) (135 PJ Central share) of Coal Seam Gas (CSG) in
ATP 2031. The Range Gas Project is at the doorstep of the east coast gas market and could nearly double Central’s reserve base and annual
sales volumes.
The resources, certified by international certifier NSAI, exceeded expectations and resulted from a successful four-well exploration
programme conducted safely, on schedule and on budget during July and August 2019. These wells provided exciting results,
demonstrating average coal thickness of 30 metres and drill stem tests indicated that permeability is in line with, or better than,
expectations – including the deeper Taroom seams. The excellent permeability and coal thickness suggests that the area should be suitable
for gas production from low-cost, un-fracked vertical wells.
Given these excellent results, the joint venture commenced working towards a FID for a substantial CSG development. These pre-FID
activities include conducting environmental studies, securing approvals, undertaking engineering studies, selecting equipment and ordering
long-lead items. Planning for pre-FID activity, including an appraisal pilot, is well advanced.
Location of the Range Gas Project (ATP 2031) in relation to other coal seam gas projects in the Surat Basin
Activity was paused in March 2020 as a prudent fiscal response to business uncertainty associated with the COVID-19 pandemic and the
severe gas market downturn. The JV is presently considering opportunities to restart pilot activities and approvals in the 2nd half of CY2020,
with FID expected about 12 months after restart.
It is anticipated that finalisation of development plans and a successful appraisal pilot will lead to a conversion of 2C contingent resource to
2P certified reserves. The 2C is currently classified as “development pending”, which is the highest category of contingent resource,
requiring only satisfaction of FID milestones such as development plans, access to infrastructure and offtake agreements for conversion to
certified 2P gas reserves. First gas sales from the Range Gas Project will be targeting an expected shortfall of gas supply in eastern Australia
from 2023 onwards.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
11
OPERATING AND FINANCIAL REVIEW
The Range Gas Project is situated in Queensland’s Surat Basin, a geological province whose CSG reserves have attracted billions of dollars
of investment over the last decade and now supplies gas to both the domestic market and international consumers through Gladstone’s
LNG facilities. There are a large number of CSG wells in adjacent blocks and areas within the Walloons Coal Measures fairway in the same
depth band as the Range Gas Project that have been successfully developed for production. The permit area covers 77 km2 and is located
approximately 28 km north-west of the town of Miles which lies halfway between the Wooleebee Creek and Bellevue CSG developments.
Exploration Assets
Granted Petroleum Permits, Licences and Application Interests
The current Central portfolio encompasses opportunities within the Amadeus, Southern Georgina, Wiso and Surat basins. The total area
held by Central for exploration (both granted and under application) within these basins is 181,875 km2 (72,197 km2 granted and
109,678 km2 under application).
The Amadeus Basin has, to date, been a focus for the majority of Central’s exploration activity, with ~170,000 km2 of areal extent, five
known working petroleum systems and four fields having produced significant quantities of oil and gas (one oil field currently suspended).
Notwithstanding this production history, the Amadeus Basin is one of the few remaining large, under-explored, working hydrocarbon
systems onshore Australia, with only a total of 39 exploration wells and ~14,500 km of 2D seismic acquired across the entire basin. This can
in part be attributed to the small and historically oversupplied Northern Territory gas market which has limited investment in the region.
Following connection to the east coast gas market via the NGP in January 2019, Central’s NT exploration assets now have a clear pathway
to an attractive east coast gas market. Recognising this new market dynamic, Central has undertaken a full exploration portfolio review,
enabling the definition of an attractive exploration drilling campaign targeting lower-risk, higher value targets. In addition, a basin-wide
play-based analysis was advanced in order to assess longer term and potentially transformational exploration programmes beyond 2020.
The proposed Amadeus to Moomba Gas Pipeline will, if developed, provide a more direct, efficient route to east coast markets and is likely
to provide a catalyst for increased exploration in the Amadeus Basin.
12
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
Dukas-1 (EP112)
Southern Amadeus Basin, Northern Territory
(CTP – 30% interest, Santos 70%)
Dukas-1 is located in EP112 approximately 175 km south west of Alice Springs with a possible structural closure in excess of 400 km2,
making it one of the largest known onshore conventional gas prospects in Australia, with multi-Tcf gas potential.
Given the potential size, success at Dukas would be company changing. In addition, several other large ‘lookalike” sub-salt closures, such as
the Zevon lead in EP115, have been identified from interpretation of earlier seismic data acquired in the Southern Amadeus Basin. As such,
success at Dukas-1 has the potential to unlock a significant new hydrocarbon province in the Southern Amadeus Basin and become a major
new source of gas for the east coast market.
Dukas-1 was designed to test a large regional high optimally located to receive charge from an interpreted Neoproterozoic depocenter. The
primary reservoir objective is the Heavitree Quartzite/fractured basement, a petroleum system which has been proven to be hydrocarbon
bearing at Mt. Kitty-1 and McGee-1.
Location map of Dukas-1 and EP112
The Dukas-1 exploration well had a proposed total depth of 3,850m and reached a depth of 3,704m in August 2019 when it encountered
formation pressures much higher than predicted in association with a combination of hydrocarbon and inert gasses above the target
reservoir formation. Both of these are positive indications for a working petroleum system and effective seal at the Dukas location.
Santos (as operator) subsequently assessed that the technical requirements to continue drilling were in in excess of the capabilities of the
rig and surface equipment and drilling activity was suspended and the rig released.
The primary reservoir objective, the Heavitree Quartzite / fractured basement, is yet to be penetrated.
Prior to drilling Dukas-1, the JV relied solely on seismic imaging through a thick section of evaporites and complex thrust faulting to map
the structure. Specific detail of the structural attitude of the strata overlying the target, however, is now available from recently acquired
Dukas-1 well log data and greatly improves structural mapping.
Importantly, the revised structural closure remains very large at greater than 400 km2, which is comparable in area to multi-Tcf fields such
as Bayu-Undan in the Timor Sea. In addition, the revised mapping creates an opportunity to drill a more crestal well, which could increase
the potential for a successful outcome.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
13
OPERATING AND FINANCIAL REVIEW
Work is now underway to assess various options to intersect the target formation using specialised high-pressure equipment. The three
primary options are:
1. Re-entry of the suspended Dukas-1 well and continue drilling into the formation (limited to operations possible within existing
casing sizes);
2. Twinning the existing Dukas-1 well by drilling a new well immediately adjacent to the existing suspended well (using new casing
to improve drilling and testing opportunities); or
3. Drilling a new well at a more crestal location.
A decision is expected by late 2020 and the targeted spud timing for the selected option is as soon as possible in 1H of calendar year 2022.
This schedule allows the opportunity to consider the various options (including the crestal well), along with the associated well designs,
permits and approvals, and sourcing of high-pressure equipment and drill rig.
Commercially, Santos can elect for Central to be carried for the first $3 million ($10 million gross JV) of its future Dukas well costs in certain
circumstances. In return for a carry by Santos, and if Santos so elects, Central will transfer an additional 30% equity in EP82 to Santos
(excluding the Orange prospect in which Central has a 100% interest). This would ensure consistent equity interests across all
Central/Santos JV tenures in the middle Southern Amadeus Basin. Santos would also pay to Central certain back-costs associated with the
transferred interest for field activities conducted in EP82 from July 2020.
Should Santos not elect to carry Central’s expenditure in Dukas in exchange for the option to have 30% equity in EP82, then the equity
interest in EP112 (with Dukas-1) will revert from 70% Santos / 30% Central to 55% Santos / 45% Central.
Amadeus Exploration Programme
Southern Amadeus Basin, Northern Territory
In October 2019, a potentially Company-changing exploration programme was announced, consisting of five high-graded drillable targets
and two appraisal tests. These exploration targets range from lower to more moderate-risk opportunities with compelling investment
justifications, including rapid commercialisation, attractive brownfield economics, proximity to existing infrastructure, and the potential to
be quickly implemented. The exploration programme targets natural fractures within conventional formations. No artificial stimulation
(hydraulic fracturing) is proposed for this programme.
Location map of priority exploration targets
14
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
Work on the exploration programme progressed during the year, finalising well designs and progressing the approval processes required
for exploration in the Northern Territory. Permit and environmental management plan applications have been prepared and lodged and
well designs are at an advanced stage.
From the original programme, three high potential gas prospects have been prioritised for drilling:
(a) Palm Valley Deep: Deeper reservoir untested within the field (proven at Dingo). Minimal investment would be required in a success
case with a potentially large resource. It is planned to sidetrack horizontally into the currently productive Pacoota section for extra
production that could be quickly commercialised.
(b) Orange-3 (EP82 DSA): Existing wells have proven hydrocarbons at the shallow Arumbera level (productive zone at Dingo). Additional
targets identified in a deeper section of the structure are volumetrically significant and close to the existing Dingo pipeline.
(c) Dingo Deep: The well will be located crestally in the field and provide an additional production well at the currently producing
Arumbera level and also explore additional deeper reservoir targets.
In addition, appraisal at the Mereenie Stairway could be undertaken, subject to JV approval. This would require reperforating and testing
the Stairway formation from one or more existing wells. This is an undeveloped section of Mereenie with the potential to convert 2C to 2P.
Priority exploration target formations in relation to existing wells
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
15
OPERATING AND FINANCIAL REVIEW
The proposed exploration programme will target mean prospective resources, net to Central, of up to 593 PJ of gas (408 PJ best estimate)
and, subject to JV approval, 54 PJ of 2C contingent resource.
Lead / Prospect
Dingo Deep
Orange-3
Palm Valley Deep
Aggregate Total
Appraisal target
Mereenie Stairway
Prospective Resource1
Best estimate (P50)
(PJ)
49
284
75
408
2C Contingent Resource2
Mean
(PJ)
69
401
123
593
(PJ)
54
1.
Prospective Resource: As first reported to ASX on 7 August 2020. The volumes of prospective resources represent the unrisked recoverable
volumes derived from Monte Carlo probabilistic volumetric analysis for each prospect. Inputs required for these analyses have been derived from
offset wells and fields relevant to each play and field. Recovery factors used have been derived from analogous field production data.
Cautionary statement: the estimated quantities of petroleum that may potentially be recovered by the application of a future development
project(s) relate to undiscovered accumulations. These estimates have both an associated risk of discovery and a risk of development. Further
exploration appraisal and evaluation is required to determine the existence of a significant quantity of potentially moveable hydrocarbons.
2.
Contingent Resource: As first reported to ASX on 13 November 2018.
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.
EP115
Western Amadeus Basin, Northern Territory
(CTP – 100% interest)
EP115 is located in the north-western section of the Amadeus Basin between the Mereenie Oil & Gas Field and the Surprise Oil Field/
Mamlambo oil prospect.
Location of the Zevon lead in EP115
16
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
Following the promising indications and technical data derived from the Dukas-1 well, Central is now considering the opportunity to
accelerate exploration in EP115 which contains several other large sub-salt targets, such as the Zevon lead which has been defined as a
very large closure (circa 1,600 km2) from seismic and gravity studies.
With the Dukas target drilling window in 1H 2022, Central could use the Dukas rig for drilling in EP115. This would save considerable cost
and provide another potentially company-changing exploration well in a permit that is 100% controlled by Central. Planning for a 500 km
2D seismic survey in 2021 is underway to identify a drilling location to enable sharing of the Dukas rig and specialised high-pressure drilling
equipment in 2022.
Ooraminna Discovery (RL3 and RL4)
(CTP – 100% interest)
Two wells have been drilled at Ooraminna with both wells having proved gas flow from the Pioneer Formation. Although the flow rates
were sub-economic, the wells were drilled in an area with apparent low natural fracture density. Following the portfolio review, the
proposed Ooraminna-3 well has been assessed as being less compelling on a risk-return basis than the identified priority exploration
targets and will be considered for following programmes after results from the priority programme are analysed.
Southern Amadeus Basin, Northern Territory
Various Exploration Permits (see table on page 105)
The primary exploration objective within these permits is maturing large sub-salt leads in the Neoproterozoic. Potential secondary
reservoir objectives are developed within the post-salt units including the Areyonga Formation and Pioneer Sandstone, both of which are
gas bearing at the Ooraminna discovery.
In addition to the sub-salt prospects, Central continues to mature its geological interpretations in these permits, seeking to identify a
variety of other exploration play types and targets which could be prospective for hydrocarbons and/or helium. A full play-based-
exploration review is underway with the objective of identifying new plays and fully understanding existing plays.
Exploration Application Areas, Northern Territory
Amadeus, Pedirka and Wiso Basins — Various Areas (see table on page 105)
The Company continued to evaluate a number of these areas and has been working to gain Native Title/Aboriginal Land Rights Act
clearance and secure the other necessary approvals in advance of the award of exploration permit status.
Across the Amadeus Basin, further review of the seismic, well, magnetic and recently acquired gravity data was completed, resulting in an
inventory of leads and prospects. Play types and leads are also being developed for the under-explored section underlying the proven
Ordovician Larapintine system which is believed to be prospective for gas. In the Western Amadeus Basin, a preliminary seismic
programme has been designed to target identified structural trends and leads with the aim of defining areas for a follow up infill seismic
survey.
In the Wiso Basin, a gravity survey was conducted by Geoscience Australia and the Northern Territory Geologic Survey in 2013, which has
provided Central with improved detail of structural trends. Interpretation and forward modelling in conjunction with magnetic, borehole
and outcrop data has led to the generation of a depth to basement map. This will help with the planning of a proposed seismic acquisition
programme which will form part of the first phase of exploration once tenure is granted.
ATP909, ATP911 and ATP912
Southern Georgina Basin, Queensland
(CTP—100% interest)
Geology and geophysical studies continued, focussing on the Ethabuka structure.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
17
OPERATING AND FINANCIAL REVIEW
RESERVES AND RESOURCES STATEMENT
Net proved & probable (2P) oil and gas reserves were 161.2 PJE at 30 June 2020, a net increase of 11.4 PJE after accounting for production
during the year. Additional 2C contingent gas resources of 135 PJ were recognised for the first time at the Range coal seam gas project in
Queensland’s Surat Basin after a successful exploration drilling in mid-2019.
Aggregate Reserves and Resources
(Central share)
Unit
As at
30/06/2019
1 July 2019 – 30 June 2020
Production Adjustments 30/06/2020
As at
Comprising1
Developed Undeveloped
Oil
Proved reserves (1P)
mmbbl
Proved plus probable reserves (2P) mmbbl
mmbbl
Contingent Resources (2C)
0.68
0.87
0.10
(0.09)
(0.09)
—
0.18
0.19
—
0.77
0.97
0.10
0.55
0.83
—
Gas
Proved reserves (1P)
Proved plus probable reserves (2P)
Contingent Resources (2C)
PJ
PJ
PJ
120.18
144.69
104.78
(10.64)
(10.64)
—
13.71
21.51
135.10
123.24
155.56
239.88
90.28
124.64
—
0.22
0.14
—
32.96
30.92
—
1 All developed and undeveloped 1P and 2P reserves are located in the Amadeus Basin geographical area.
Reserves and Resources by Field
(Central share)
Unit
Mereenie, oil
Proved reserves (1P)
mmbbl
Proved plus probable reserves (2P) mmbbl
mmbbl
Contingent Resources (2C)
Mereenie, gas
Proved reserves (1P)
Proved plus probable reserves (2P)
Contingent Resources (2C)
Palm Valley
Proved reserves (1P)
Proved plus probable reserves (2P)
Contingent Resources (2C)
Dingo
Proved reserves (1P)
Proved plus probable reserves (2P)
Range (Surat Basin, Qld)
Contingent Resources (2C)
PJ
PJ
PJ
PJ
PJ
PJ
PJ
PJ
PJ
Estimates may not arithmetically balance due to rounding.
As at
30/06/2019
1 July 2019 – 30 June 2020
Production
Adjustments
As at
30/06/2020
0.68
0.87
0.10
71.19
81.55
91.20
18.49
25.83
13.58
30.49
37.32
(0.09)
(0.09)
—
(5.48)
(5.48)
—
(3.93)
(3.93)
—
(1.23)
(1.23)
0.18
0.19
—
3.54
15.76
—
10.16
5.76
0.10
—
—
0.77
0.97
0.10
69.26
91.82
91.20
24.73
27.66
13.68
29.26
36.08
—
—
135.00
135.00
Qualified Petroleum Reserves and Resources Evaluator Statement
The information contained in this Reserves and Resources Statement is based on, and fairly represents, information and supporting
documentation reviewed by Mr Kevan Quammie who is a full-time employee of Central Petroleum holding the position of Development &
Appraisal Manager. Mr Quammie holds an M.Sc. Petroleum and Natural Gas Engineering from the Pennsylvania State University, is a
member in good standing of the Society of Petroleum Engineers, is qualified in accordance with ASX listing rule 5.41. and has consented to
the inclusion of this information in the form and context in which it appears.
18
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
The reserves and resources information in this document relating to:
•
•
•
the Mereenie and Palm Valley Fields were first reported to ASX on 24 July 2020 and are based on, and fairly represent information
and supporting documentation reviewed by Mr John Hattner who is a full-time employee of Netherland, Sewell & Associates, Inc.,
holding the position of Senior Vice President and is a member in good standing of the Society of Petroleum Engineers;
the Dingo Field were first reported to ASX on 24 July 2020 and are based on, and fairly represent information and supporting
documentation reviewed by Mr Kevan Quammie who is a full-time employee of Central Petroleum Limited holding the position of
Development and Appraisal Manager and is a member in good standing of the Society of Petroleum Engineers; and
the Range Gas Project are as at 15 August 2019, were first reported to the market on 20 August 2019 and are based on, and fairly
represent information and supporting documentation reviewed by Mr John Hattner who is a full-time employee of Netherland,
Sewell & Associates, Inc., holding the position of Senior Vice President and is a member in good standing of the Society of
Petroleum Engineers.
Central Petroleum Limited is not aware of any new information or data that materially affects the information included in this document
and all the material assumptions and technical parameters underpinning the estimates in the relevant market announcement continue to
apply and have not materially changed.
Reserves and resources estimates are prepared by suitably qualified personnel in a manner consistent with the Petroleum Resources
Management System (PRMS) 2018 published by the Society of Petroleum Engineers (SPE). Reserves and resources estimates are reviewed
at least annually or when new technical or commercial information become available. Additionally, external certification is conducted
periodically.
RISK MANAGEMENT
Central Petroleum maintains a robust and disciplined focus on effective risk management. We do this so that we better understand
uncertainty and manage risks, to help achieve our objectives.
Our risk management process is designed to recognise and manage risks that have the potential to materially impact on Central’s business
objectives. This process is aligned to the international standard ISO31000 for risk management and assesses potential risks across our
business and considers impacts on the health and safety of our employees, the environment and communities in which we operate, our
financial stability, our reputation and legal and compliance obligations.
Principal risks and uncertainties at 30 June 2020
The principal risks and uncertainties outlined in this section may materialise independently, concurrently or in combination and may impact
Central’s ability to meet its strategic objectives.
Context
Risk
Mitigation
Exploration and Appraisal
Our future growth depends
on our ability to identify,
acquire, explore and develop
reserves.
Unsuccessful exploration and renewal of
upstream resources may impede delivery of
our strategy.
Exposure to reserve depletion is addressed through
our exploration strategy. We continue to analyse
existing acreage for exploration drilling prospects
and undertake extensive subsurface modelling and
uncertainty analysis to determine the most likely
production outcomes across our fields. Our
disciplined management of opportunities and
acquisitions, together with the application of proven
technologies and recovery processes, further
addresses this risk.
Oil and Gas Reserves
Commercialisation of
hydrocarbons reserves is a
key contributor to our long-
term success.
Uncertainty in hydrocarbon reserve estimation
and the broad range of possible recovery
scenarios from existing resources could have a
material adverse effect on our operations and
financial performance.
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.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
19
OPERATING AND FINANCIAL REVIEW
Context
Operating
Production and delivery of
hydrocarbon products to plan
are key elements of our
operational and financial
performance and directly
impact shareholder returns.
Risk
Mitigation
Reservoir / field performance is subject to
subsurface uncertainty. The actual
performance could vary from that forecasted,
which may result in diminished production and
/or additional development costs.
We continually monitor field performance and
schedule production optimisation and development
activities to extract maximum value from the field
and to mitigate any potential reservoir under-
performance.
Our facilities are subject to hazards associated
with the production of gas and petroleum,
including major accident events such as spills
and leaks which can result in a loss of
hydrocarbon containment, diminished
production, additional costs, environmental
damage or harm to our people, reputation or
brand.
Our operational performance is based on a
framework of controls which enable the
management of these risks. We have in place asset
integrity management processes, inspections,
maintenance procedures and performance
standards across all infrastructure to maximise
reliable and safe operations.
Central maintains insurance in line with industry
practice and sufficient to cover normal operational
risks. However, Central is not insured against all
potential risks because not all risks can be insured
cost effectively. Insurance coverage is determined by
the availability of commercial options and cost/
benefit analysis, considering Central’s risk
management programme.
In addition, our operations can be negatively
impacted by employee and contractor
availability due to the impacts associated with
COVID-19 including shutting down for a period.
All operational employee and contractor activities
are managed under a Pandemic (COVID-19)
Management Plan in order to minimise the risk of
impacts to operations.
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 sources to ensure
the business is appropriately capitalized to sustain
ongoing operations and growth plans. We also
actively seek partnering opportunities to share risks
and assist in funding key activities on a project-by-
project basis.
Oil revenue represented less than 10% of
consolidated sales revenue in FY2020 which was
impacted due to COVID driven market conditions.
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.
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.
Financial
Our revenue is from the sale
of hydrocarbons. This
underpins Central’s financial
performance.
Central is exposed to USD commodity price
variability with respect to crude oil sales which
are impacted by broader economic factors
beyond our control.
Central is exposed to gas commodity prices
with respect to gas sales, all of which are to the
Northern Territory and Australian east coast
markets. In addition to normal demand and
supply forces, gas prices in these markets are
subject to risk of Government intervention in
the form of the Australian Domestic Gas Supply
Mechanism; although this mechanism is
focused on availability of supply and is not
considered to have significant potential impact
on price.
20
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
Context
Risk
Mitigation
Health and Safety
Health and Safety is at the
heart of all activities and
decisions at Central.
Health and Safety incidents or accidents may
adversely impact our people, the communities
in which we operate, our reputation and/or
our licence to operate.
Potential exposure of employees and
contractors to COIVD-19 and the potential
transmission to communities in which we
operate.
Health and Safety is an area of focus for Central and
our risk management framework includes auditing
and verification processes for our critical controls.
We also regularly review our operations and
activities to ensure we operate with the required
standards of safety management.
All operational activities including travel to and from
sites are managed under a Pandemic (COVID-19)
Management Plan. Although we continue our
support, we have ceased all company-initiated face
to face engagement with traditional owner
communities. We continue to monitor and align our
standards and approach with guidance from various
government and health authorities.
Environment
Our environmental
performance underpins our
licence to operate.
Information Technology
We are reliant upon our
systems and infrastructure
availability and reliability to
support the business
operating safely and
effectively.
Human Resources
We must have the right
capability and capacity within
our personnel to perform in
line with expectations to
support our business.
Geographic Concentration
We face risks associated with
the concentration of our
production assets.
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
programme 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.
The integrity, availability and reliability of data
and intellectual property within Central’s
information technology systems may be
subject to intentional or unintentional
disruption (e.g. cyber security attack).
Our exposure to cyber security risk is managed by a
proactive and continuing focus on system controls
such as firewalls, restricted points of entry, multiple
data back-ups and security monitoring software. We
are also bolstering our system processes and policy
controls.
Failure to establish and develop sufficient
capability to support our operations may
impact achievement of our objectives.
Central’s focus remains on securing and developing
the right people to support the development of our
portfolio of assets and opportunities. Our focus
remains on creating a positive employer value
proposition, planning our resource requirements and
attracting talented individuals. We also proactively
engage contractors to supplement any short-term
gaps in capability and capacity to support the
execution of our business plans.
Central’s revenue is derived from oil and gas
production in the Amadeus Basin leaving
Central exposed to downsides associated with
weather conditions and infrastructure failure.
We ensure that appropriate insurance is in place to
mitigate the impact of any extended business
interruption. The Range coal seam gas project in the
Surat Basin aims to begin to geographically diversify
our business. We are also investigating other new
ventures outside of the Amadeus Basin.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
21
OPERATING AND FINANCIAL REVIEW
Context
Risk
Mitigation
Regulatory Compliance / Change
Our business activities are
subject to extensive
regulation and government
policy. Our business
performance is under-pinned
by our licence to operate.
Central is subject to various national and local
laws, regulations and approvals, which are
subject to change - such as the proposed
reserved blocks (no-go zones) for petroleum
activities in the Northern Territory. These,
along with other changes, could impact the
exploration, development, production,
transportation and storage of our products
and along with it our future prospects.
Climate Change
We face risks associated with
climate change including
fluctuations in product
demand, carbon pricing and
increased stakeholder
expectations.
Demand for oil and gas may subside over the
longer term 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.
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 also proactively
maintain relationships with governments, regulators
and stakeholders within jurisdictions in which we
operate.
We are focused on ensuring our portfolio is robust in
a potentially carbon constrained market and engage
proactively with key industry and government
stakeholders. Our development is predominantly
focused on gas as a transition fuel which could see
demand for natural gas increase as part of a clean
energy future compared to other energy sources.
Central also seeks value accretive opportunities to
reduce carbon emissions.
Access to Infrastructure
Our financial performance
and growth strategy are
dependent on access to third
party owned infrastructure.
Negative impacts to revenue as a result of
infrastructure failure, increased tariffs or
restricted access to third party owned
infrastructure.
We seek to work closely with customers and
suppliers of infrastructure to mitigate the risk of
delays or failure. We continue to explore alternative
routes to market to diversify risk where possible.
Community
Our proactive engagement
and support of local and
indigenous communities is at
the core of how we operate.
Project Delivery
Our growth strategy is
dependent on our ability to
successfully deliver value
adding projects.
Joint Ventures
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, impacting our social licence
to operate.
We work in conjunction with our key stakeholders
and have established programmes to support and
assist the communities in which we operate through
donations, sponsorships, local procurement, training
and providing ongoing local employment
opportunities.
Central is exposed to market and industry
conditions - some beyond our control, which
may impact project delivery and lead to cost
overruns or schedule delays when developing
and executing our portfolio of capital projects.
We utilize an established project management
framework which is supported by skilled and
experienced personnel to govern and deliver major
projects.
Although we operate most of
the tenements we hold, we
are dependent on technical
and commercial alignment
with our joint venture
partners.
Misalignment between joint venture partners
can lead to scarcity of available capital and
may impact the prioritisation of exploration,
development or production opportunities. This
can lead to delayed approvals which may
impact Central’s growth strategy.
We work closely with our joint venture partners to
achieve mutually beneficial outcomes.
22
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2020
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 2020.
DIRECTORS
The names of the Directors of the Company in office during the financial year and until the date of this report are set out below. Directors
were in office for this entire period unless otherwise stated.
Current Directors:
Mr Stuart Baker
Mr Leon Devaney
Dr Julian Fowles
Mr Wrixon Gasteen
Ms Katherine Hirschfeld AM
Dr Agu Kantsler (appointed 15 June 2020)
Mr Michael (Mick) McCormack (appointed 1 September 2020)
Former Directors:
Mr Martin Kriewaldt (resigned 2 September 2019)
PRINCIPAL ACTIVITIES
The principal activities of the Consolidated Entity constituting Central Petroleum Limited and the entities it controls consists of
development, production, processing and marketing of hydrocarbons and associated exploration.
DIVIDENDS
No dividends were paid or declared during the financial year (2019: $Nil). No recommendation for payment of dividends has been made.
OPERATING AND FINANCIAL REVIEW
The operating and financial highlights for the financial year were:
•
•
Record annual sales volumes and revenues:
o Volumes up 14% to 12.3 PJE
o
Revenues up 10% to $65 million
51% increase in EBITDAX to $33.4 million
• Maiden full year profit of $5.4 million
•
•
•
•
•
•
•
16% increase in 2P reserves to 161.2 PJE
Added 135 PJ of 2C contingent gas reserves at the Range Gas Project in the Surat Basin after completion of a successful four well
exploration programme
Dukas-1 well was suspended after encountering hydrocarbon-bearing gas from an over-pressured zone close to the primary
target and a forward plan to complete the Dukas exploration programme is now underway
Excellent safety record with no MTIs or LTIs during the year
Reduced net debt by 30% to $46.1 million and extended loan facility by 12 months to late 2021
Strengthened the Board with the appointment of Dr Agu Kantsler and Mick McCormack, both highly respected industry leaders
with proven experience in the core areas critical to Central’s future success
Subsequent to the year end, announced an MOU with highly capable partners, Macquarie Mereenie and Australian Gas
Infrastructure Group (AGIG), to progress towards a FID on a proposed major new pipeline that would enable Central’s gas to be
transported direct to the Moomba gas supply hub and the larger south-eastern Australian gas markets with significantly greater
cost efficiencies.
A detailed review of the operating and financial performance for the year ended 30 June 2020, including principle risks is provided from
pages 3 to 22 of this Annual Report.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
23
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2020
SIGNIFICANT CHANGES IN THE STATE OF AFFAIRS
The financial position and performance of the Group was particularly affected by the following events and transactions during the year
ended 30 June 2020:
•
•
•
•
•
•
Dukas-1 exploration well was suspended after encountering formation pressures much higher than predicted. Hydrocarbon-
bearing gas circulated to surface providing strong evidence of a working petroleum system.
A four well exploration programme was successfully completed at the Range Gas Project (ATP 2031). Net coal thickness was on
prognosis and permeability in line with or better than expected throughout the permit, resulting in the recognition of 135 PJ of
2C contingent resources (Central share).
Final settlement for the transfer of a 50% interest in the Range Gas Project resulted in a cash receipt of $7.7 million.
The first full year of access to the Northern Gas Pipeline was reflected in increased sales volumes, up 14% on the preceding year.
Revenues increased 10%, impacted by lower oil prices and weak gas markets in the second half of the year.
Recorded a 16% increase in 2P gas reserves.
In February 2020 the Macquarie Bank finance facility maturity date was extended by 12 months to 30 September 2021.
There were no other significant events that are not detailed elsewhere in this Annual Report.
EVENTS SINCE THE END OF THE FINANCIAL YEAR
Amadeus to Moomba Gas Pipeline
In August, Central announced an agreement to work with Australian Gas Infrastructure Group and Macquarie Mereenie Pty Ltd towards a
FID on a proposed new pipeline to enable Central’s gas to be transported direct to the Moomba gas supply hub and the larger south-
eastern Australian gas markets at a lower cost than existing routes.
Issue of shares
On 18 September 2020, the Company issued 146,215 shares to employee participants in the $1,000.00 Exempt Plan.
Issue and cancellation of share rights
On 18 September 2020, the Company issued 10,179,464 Share Rights pursuant to the Employee Rights Plan. The Company also cancelled
717,033 Share Rights on the same date and a further 211,528 on 23 September 2020.
No other matter or circumstance has arisen between 30 June 2020 and the date of this report that will affect the Group’s operations, result
or state of affairs, or may do so in future years.
LIKELY DEVELOPMENTS AND EXPECTED RESULTS OF OPERATIONS
Central is planning for a period of sustained growth in coming years, targeting a tripling of gas reserves from a new Amadeus exploration
programme in 2021 and the Range coal seam gas project in Queensland. Other large, potentially Company-changing exploration prospects,
such as Dukas and similar sub-salt leads elsewhere in the Amadeus Basin will also be pursued in coming years. The Group’s prospects and
leads in the Amadeus Basin are likely to benefit from the proposed new pipeline to the east coast via Moomba, and activities will continue
to support the development of this important new route to market.
Further information on these activities is included from pages 1 to 17 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 and 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.
24
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
INFORMATION ON DIRECTORS
Mr Leon Devaney BSc, MBA
Managing Director and Chief Executive Officer
Mr Devaney has 20 years of commercial and finance experience within the Australian oil and gas sector and holds an
MBA and BSc (Finance) from the University of Southern California, USA.
He joined Central Petroleum in 2012 and has been responsible for commercial, finance and business development
activities in various senior roles. He was instrumental in negotiating the Mereenie acquisition from Santos in 2015, as
well as the Palm Valley and Dingo Gas Field acquisition from Magellan Petroleum in 2014. Mr Devaney was appointed
Chief Executive Officer, effective February 2019, after serving as Acting CEO since July 2018.
Prior to joining Central Petroleum, he worked at QGC and played a pivotal role in its growth from a small cap gas
exploration company into a multi-billion-dollar takeover target by the BG Group in 2008. He continued with BG
following the QGC takeover, where he served as General Manager, Gas and Power, responsible for the domestic gas
and electricity portfolio.
Prior to QGC, Mr Devaney held senior roles at Deloitte in the Corporate Finance Advisory Group where he was active in
structuring and implementing commercial and financing transactions for major energy and infrastructure projects
throughout Australia.
Mr Wrixon F Gasteen BE (Mining) (Hons) QLD, MBA (Distinction) Geneva
Independent Non-executive Chairman
Wrix Gasteen has over 30 years’ experience in mining, oil and gas, and manufacturing industries in Australia and Asia.
He is an experienced Managing Director and CEO, Executive Director, Independent Non-Executive Director and
Chairman of both listed and private companies in Australia, Singapore, Malaysia, and the United States. He is a senior
advisor to Australian companies.
He has held senior management positions in the resources industry in Australia. As Chief Mining Engineer, he led the
Exploration and Engineering team that discovered and then developed the Boundary Hill Coal Mine in Central
Queensland. He became its inaugural Mine Manager.
As Managing Director and CEO of Hong Leong Asia Limited, listed on the Singapore Stock Exchange (SGX: HLA), he
transformed and grew the company seven fold, through acquisitions and organic growth, from a loss making company
to a highly profitable conglomerate with 14,000 employees, $2.2 billion in sales, 80% of which were in China and SE
Asia. Mr Gasteen was also Director of Tasek Corporation (cement) listed on Kuala Lumpur Stock Exchange (KLSE) and
Chairman and President of China Yuchai International (diesel engines) listed on the New York Stock Exchange (NYSE).
During his term as Managing Director and CEO of HLA, he was presented with two successive annual awards by the
Securities Investors Association of Singapore (SIAS) for Corporate Transparency. The BRW ranked Mr Gasteen No.3 in
their Top 20 Australians Managing in Asia.
Mr Gasteen is an Executive Director of Australian dairy milk powder products company, CBS International. He is a
Director and co-founder of Ikon Corporate (Singapore), established in 2007 to provide corporate advisory and
management consulting services.
Mr Stuart Baker BE(Elec), MBA, AICD
Independent Non-executive Director
Mr Baker was appointed as a Director in December 2018 and has more than four decades of experience in the oil and
gas sector and currently provides independent advice to corporates and investors in the Australian oil and gas industry.
Previously he was Executive Director, Morgan Stanley with dual roles as Co-Head Asia Oil, Gas and Chemicals Research
and team leader, Australian energy, mining and utility research, with positions held over a 13-year period. He also held
senior equity research positions in oil and gas, at Macquarie Bank and Bankers Trust, and as a Petrophysical Engineer at
Schlumberger Inc. based in South-east Asia, rising to General Field Engineer.
Mr Baker is currently a member of the investment committee of resource focused ASX listed Lowell Resources Fund, is a
strategic advisor to Karoon Gas Australia Ltd and a Member of the Board of Governors, Shelford Girls Grammar School,
Melbourne.
Mr Baker is a member of the Australian Institute of Company Directors and holds a BE(Elec) from the University of
Melbourne and an MBA from the Melbourne School of Management.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
25
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2020
Dr Julian Fowles PhD, BSc (Hons), GDipAFI, GAICD
Independent Non-executive Director
Dr Fowles was appointed as a Director in June 2019 and is a petroleum industry professional with over 30 years in
international leadership roles, including 17 years with Shell International, as well as positions with other major listed
companies. He has extensive board, shareholder and analyst engagement experience.
Most recently Dr Fowles was a senior executive with Oil Search limited, leading the PNG operated and non-operated oil
and LNG production and development businesses. He was previously the executive leading Oil Search’s Exploration and
New Business teams and has also been involved in the development and implementation of Oil Search’s opportunity
development framework, targeting major projects through key assurance processes from pre-concept to FID.
Dr Fowles is a Graduate of the Australian Institute of Company Directors and holds a BSc (Hons) from the University of
Edinburgh and a PhD from the University of Cambridge. Dr Fowles also holds a Graduate Diploma in Applied Finance
and Investment.
Directorships of other listed companies in the last three years: FAR Limited from 2019.
Ms Katherine Hirschfeld AM BE(Chem) UQ, HonFIEAust, FTSE, FIChemE, CEng, FAICD
Independent Non-executive Director
Ms Hirschfeld was appointed as a Director in December 2018 and is a highly regarded non-executive director, having
served on company boards listed on the ASX, NZX and NYSE, as well as government and private company boards. She is
currently the Chair of Powerlink and a board member of Qld Urban Utilities and Tellus Holdings Ltd.
Ms Hirschfeld has also been a board member and President of UN Women National Committee Australia and non-
executive director of Energy Queensland, Tox Free Solutions, InterOil Corporation, Broadspectrum and Snowy Hydro.
Previously she had leadership roles with BP in oil refining, logistics, exploration and production located in Australia, UK
and Turkey.
Ms Hirschfeld was recognised in the AFR/Westpac 100 Women of Influence 2015, by Engineers Australia as one of
Australia’s Top 100 Most Influential Engineers 2015 and as an Honorary Fellow in 2014. She is a member of Chief
Executive Women and a Fellow of the Australian Institute of Company Directors and the Academy of Engineering and
Technology. She is also an executive mentor/coach with Merryck & Co.
In 2019 Ms Hirschfeld was appointed a Member of the Order of Australia (AM) for significant service to engineering, to
women, and to business.
Directorships of other listed companies in the last three years: Tox Free Solutions Limited from 2013 to 2018.
Dr Agu Kantsler BSc (Hons), PhD, GAICD, FTSE
Independent Non-executive Director
Dr Kantsler joined the Central Board in June 2020 and is one of Australia’s most respected and experienced petroleum
exploration executives, having led Woodside Petroleum’s world-wide exploration, business development and
geotechnical activities as Executive Vice President Exploration and New Ventures from 1995 to 2009.
Prior to joining Woodside, Dr Kantsler worked for Shell in various international locations and has served as Director and
Chairman of the Australian Petroleum Production & Exploration Association (APPEA). Dr Kantsler is Managing Director
of Transform Exploration Pty Ltd, a Non-executive Director of Oil Search Limited since 2010 and a former President of
the Chamber of Commerce and Industry WA.
Directorships of other listed companies in the last three years: Oil Search Limited from 2010.
26
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
Mr Michael (Mick) McCormack BSurv, GradDipEng, MBA, FAICD
Independent Non-executive Director
Mr McCormack was appointed as a Director on 1 September 2020 and has over 35 years’ experience in the energy
infrastructure sector in Australia and his career has encompassed all aspects of the sector, including commercial
development, design, construction, operation and management of most of Australia’s natural gas pipelines and gas
distribution systems. His experience extends to gas-fired and renewable power generation, gas processing, LNG and
underground storage.
Mr McCormack is a former Managing Director and CEO of APA Group and former Director of Envestra (now Australian
Gas Infrastructure Group), the Australian Pipeline Industry Association (now Australian Pipelines and Gas Association)
and the Australian Brandenburg Orchestra. He is a director of the Clontarf Foundation and the Australian Brandenburg
Orchestra Foundation and a Fellow of the Australian Institute of Company Directors.
Directorships of other listed companies in the last three years: Managing Director of APA Group (Australian Pipeline
Limited) from 2006 to 2019, and Director of Austal Limited from September 2020.
COMPANY SECRETARY
Mr Daniel White LLB, BCom, LLM
Mr White is an experienced oil and gas lawyer in corporate finance transactions, mergers and acquisitions, equity and
debt capital raisings, joint venture, farmout and partnering arrangements and dispute resolution. He has previously
held senior international based positions with Kuwait Energy Company and Clough Limited.
DIRECTORS’ MEETINGS
The numbers of meetings of the Company’s board of directors and of each board committee held during the financial year, and the
numbers of meetings attended by each Director were:
Director
Stuart Baker
Leon Devaney
Julian Fowles
Wrixon Gasteen
Katherine Hirschfeld AM
Agu Kantsler3
Martin Kriewaldt4
Full Meeting of
Directors
Audit Committee
Risk Committee
Remuneration &
Nominations
Committee
Community Affairs
Committee
Eligible1
Attended
Eligible1
Attended2
Eligible1
Attended2
Eligible1
Attended2
Eligible1
Attended2
16
16
16
16
16
—
3
16
16
15
16
15
—
3
4
—
—
4
4
—
—
4
3
4
4
4
—
—
—
—
4
4
4
—
—
3
4
4
4
4
—
—
5
—
5
6
—
—
—
5
2
5
6
2
—
—
—
—
—
2
2
—
—
1
2
—
2
2
—
—
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 Agu Kantsler was appointed 15 June 2020.
4 Martin Kriewaldt resigned 2 September 2019.
SHARES UNDER OPTION
(a) Options granted during or since the end of the financial year to directors and the five most highly remunerated officers of the
Company as part of their remuneration are:
Name of officer
Date granted
Vesting Date
Exercise Price
Expiry Date
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson
7 Nov 2019
20 Aug 2019
20 Aug 2019
20 Aug 2019
20 Aug 2019
30 June 2022
30 June 2022
30 June 2022
30 June 2022
30 June 2022
$0.20
$0.20
$0.20
$0.20
$0.20
30 June 2023
30 June 2023
30 June 2023
30 June 2023
30 June 2023
Number of
options granted
5,105,000
4,170,025
2,750,000
3,333,333
2,792,758
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
27
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2020
(b) Unissued ordinary shares of Central Petroleum Limited or interests under option at the date of this report are as follows:
Class
Issue Price
Exercise Price
Expiry Date
Number on issue
Unlisted employee options
Nil
$0.20
30 Jun 2023
18,151,116
(c) No shares were issued by Central Petroleum Limited during or since the end of the year on the exercise of options.
ENVIRONMENTAL REGULATION
The Consolidated Entity is subject to significant environmental regulation.
The Consolidated Entity aims to ensure the appropriate standard of environmental care is achieved and, in doing so, that it is aware of and
is in compliance with all environmental legislation. The Directors of the Company and the Consolidated Entity are not aware of any breach
of environmental legislation for the year under review.
INSURANCE OF DIRECTORS AND OFFICERS
During the financial year, the Group paid premiums to insure Directors and officers of the Group. The contracts include a prohibition on
disclosure of the premium paid and nature of the liabilities covered under the policy.
AUDITOR’S INDEPENDENCE
A copy of the Auditor’s Independence Declaration as required under section 307C of the Corporations Act 2001 is set out on page 44.
ROUNDING OF AMOUNTS
The company is of a kind referred to in ASIC Legislative Instrument 2016/191, relating to the ‘rounding off’ of amounts in the directors’
report. Amounts in the directors’ report have been rounded off in accordance with the instrument to the nearest thousand dollars, or in
certain cases, to the nearest dollar.
NON-AUDIT SERVICES
During the year the Company engaged the auditor, PricewaterhouseCoopers (PwC), on assignments additional to their statutory audit
duties where the auditor’s expertise and experience with the Company and/or the Consolidated Entity was important.
Details of amounts paid or payable to the auditor (PwC) for non-audit services provided during the year are set out below.
The Board of Directors is satisfied that the provision of the non-audit services is compatible with the general standard of independence for
auditors imposed by the Corporations Act 2001. The Directors are satisfied that the provision of non-audit services by the auditor, as set
out below, did not compromise the auditor independence requirements of the Corporations Act 2001 and did not compromise the general
principles relating to auditor independence in accordance with APES 110 Code of Ethics for Professional Accountants set by the Accounting
Professional and Ethical Standards Board.
Consolidated
PwC Australian firm:
(i)
Taxation services
Income tax compliance
R&D Services
Other tax related services
(ii) Other services
Consulting services
Total remuneration for non-audit services
28
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
2020
$
14,657
—
26,092
40,749
—
—
40,749
2019
$
8,670
35,350
44,752
88,772
8,865
8,865
97,637
EXECUTIVE SUMMARY – REMUNERATION
Dear Shareholders,
We started the FY2020 year focused on our next growth phase,
building on the strong production base established in FY2019.
The global pandemic and related market disruption has resulted
in some prudent adjustments to the implementation of our
strategy to launch Central into our next phase of growth, but our
focus remains on unlocking the full value of our impressive asset
portfolio.
Fortunately, we have gathered an experienced Board and
management team to guide the Company through the
challenging market conditions, and it is important that our
remuneration structure provides the right balance of short and
long-term incentives to align management with the interests of
shareholders.
To keep the remuneration structure relevant in these
challenging market conditions, we have made some adjustments
across all the components: base remuneration; short term
incentives; and long term incentives.
Base remuneration was increased by approximately 2% in July
2019, broadly in line with inflation and following external advice
and industry comparison. Given the weak condition of global oil
& gas markets through the second half of the year, a Company-
wide pay freeze has been implemented for the July 2020 pay
reviews.
2020 LTIP
Long term incentives are designed to align management’s
interests directly with those of shareholders. The Employee
Rights Plan / Long Term Incentive Plan (LTIP) targets half of its
reward outcomes to Central’s shares outperforming those of its
comparator companies (Relative Total Shareholder Returns) and
half to Absolute Total Shareholder Returns (TSR). Absolute TSR
must exceed 10% per annum for three years to achieve any part
of this second element and 25% per annum for three years to
receive the whole of this element.
As a result of the market weakness at year end, the LTIP’s
Absolute TSR performance for the three years from 1 July 2017
to 30 June 2020 failed to achieve the minimum growth hurdle of
10% pa and the Relative TSR placed Central below the 50th
percentile compared to its peers, resulting in no rights vesting
for this three year performance period. As included in the LTIP
plan rules, the Board has discretion to retest performance of
these hurdles at 31 December 2020.
2020 STIP
The Short Term Incentive Plan (STIP) is designed to reward
personnel for outcomes above expected performance.
Achievement of short term incentives depends on achieving
personal, departmental and corporate objectives over the year,
providing an opportunity to earn up to 10% of base
remuneration. Notwithstanding difficult business conditions in
CY2020, the Company was successful in achieving safety and
cultural heritage KPIs, increasing its 2P oil and gas reserves by
16% and successfully controlling costs. As a result, personnel
were entitled to an average 6.97% of their maximum 10%
incentive for the year.
After considering the Company’s overall performance during the
year, cash flow constraints and adverse market conditions
caused by the COVID-19 pandemic, the Board decided that Key
Management Personnel (KMP) and those managers that report
directly to them would receive their STIP entitlement in the form
of share rights, which only vest after another 3-years of service.
In addition to preserving cash reserves for growth, this will
further align senior management with shareholders and provide
a retention incentive as Central embarks on several growth
initiatives.
2020 ESOP
Following the approval by shareholders at the Company’s 2019
Annual General Meeting, we have introduced an Executive
Share Option Plan, replacing the annual LTIP for key executives
to more directly align key management objectives with
shareholder value. This was in response to shareholder concerns
regarding the complexity of the LTIP. The FY2020 grant is in lieu
of the LTIP Share Rights which would otherwise be granted over
the next three years. The Option exercise price was set at
20 cents, with a 3-year vesting period, and lapse on 30 June
2023.
Consistent with our initiative last year, we have included a
Realised Remuneration table (refer Table 1 in section H of the
Remuneration Report) to assist readers of this report to
understand the actual remuneration which the senior executives
have received this year – something which is not always clear
with the statutory reporting requirements.
We are confident the remuneration decisions taken this year will
meet the expectations of our shareholders. We will continue to
carefully monitor business and market conditions and make the
necessary adjustments to appropriately incentivise our
dedicated staff to deliver the growth strategies, which will
ultimately benefit all shareholders.
Wrixon Gasteen
Remuneration and Nominations Committee Chairman
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
29
REMUNERATION REPORT
(AUDITED)
This Remuneration Report for the year ended 30 June 2020 (FY2020) outlines the remuneration arrangements of the Group in accordance
with the requirements of the Corporations Act 2001 (Cth), as amended (the Act). This information has been audited as required by section
308(3C) of the Act.
The remuneration report is presented under the following sections:
A
B
C
D
E
F
G
H
I
J
K
Directors and Key Management Personnel (KMP)
Remuneration Overview
Remuneration Policy
Remuneration Consultants
Long Term Incentive Plan (LTIP)
Executive Share Option Plan
Short Term Incentive Plan (STIP)
Realised Remuneration
Remuneration Details
Executive Service Agreements
Non-Executive Director Fee Arrangements
A. Directors and Key Management Personnel
The Directors and key management personnel of the Consolidated Entity during the year and up to signing date of the annual report were:
Directors
Current Directors:
Mr Stuart Baker
Mr Leon Devaney
Dr Julian Fowles
Mr Wrixon Gasteen
Ms Katherine Hirschfeld AM
Dr Agu Kantsler
Non-executive Director
Managing Director and Chief Executive Officer
Non-executive Director
Non-executive Chairman
Non-executive Director
Non-executive Director (appointed 15 June 2020)
Mr Michael (Mick) McCormack
Non-executive Director (appointed 1 September 2020)
Former Directors:
Mr Martin Kriewaldt
Non-executive Chairman (resigned 2 September 2019)
Other Key Management Personnel
Mr Ross Evans
Mr Damian Galvin
Dr Duncan Lockhart
Mr Robin Polson
Mr Daniel White
Chief Operations Officer
Chief Financial Officer (commenced 5 August 2019)
General Manager Exploration
Chief Commercial Officer
Group General Counsel and Company Secretary
B. Remuneration Overview
Central’s remuneration strategy is designed to attract, motivate and retain high performing individuals and is linked to the Group’s
objectives to build long-term shareholder value. In doing so, Central adopts a pay for performance culture which is balanced by a fair and
equitable approach to the retention and motivation of its team. The remuneration strategy incorporates the following metrics:
a. Measuring Central’s achievement of its targets and performance against its peers
b. Peer company comparative indicators such as market capitalisation, size, complexity of operations and market developments
c. Adjusting to remuneration best practice
d. Market movements and its impact on the alignment of internal relativities
e.
Linking internal strategies for the achievement of improved shareholder value.
30
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
B. Remuneration Overview (continued)
Financial Year 2020
Summary of fixed and variable remuneration outcomes
Salary average increases of
2% at 1 July 2019
Where appropriate, as at 1 July 2019, a pay rise was awarded to address inflation and on account of a
change in role, responsibilities or other extenuating circumstances. A pay freeze has been implemented for
the July 2020 pay review, reflecting market conditions.
STIP
Achievement of Company-wide, departmental and individual KPIs resulted in payment of an average 69.7%
of the maximum STIP to eligible employees.
Senior management will receive share rights, instead of cash, with vesting deferred for 3 years.
LTIP Vesting
The vesting rate for Share Rights issued under the Long Term Incentive Plan for the three year period
ending 30 June 2020 was Nil, but may, at the Board’s discretion, be eligible for retesting at 31 December
2020. 146,215 shares were issued on 18 September 2020 to participants of the $1,000.00 Exempt Plan.
C. Remuneration Policy
The remuneration policy of the Company is to pay its Directors and executives amounts in line with employment market conditions
relevant to the oil and gas industry whilst reflecting Central’s specific circumstances. The Company’s remuneration practices and, in
particular, its short term and long term incentive plans are focussed on creating strong linkages between shareholder value as measured by
shareholder returns and executive remuneration. Consequently, the major component of executive incentives will be the Employee Rights
Plan/Long Term Incentive Plan (LTIP) and the Executive Share Option Plan (ESOP) rather than the Short Term Incentive Plan (STIP).
For periods up to and ending on 30 June 2020, the remuneration of directors and executives consisted of the following key elements:
Non-executive directors:
1. Fees including statutory superannuation; and
2. No participation in short or long term incentive schemes.
Executives, including executive directors:
1. Annual salary and non-monetary benefits including statutory superannuation;
2. Participation in a Short Term Incentive Plan (performance measured over a 12 month period);
3. Participation in a Long Term Incentive Plans (LTIPs or ESOPs), measured over a 3 year period); and
4. There are no guaranteed base pay increases included in any executive’s contract.
D. Remuneration Consultants
The performance of the Company depends upon the quality of its directors and executives and the Company strives to attract, motivate
and retain highly qualified and skilled management. Salaries and directors’ fees are reviewed at least annually to ensure they remain
competitive with the market.
For each annual remuneration review cycle, the Remuneration Committee considers whether to appoint a remuneration consultant and, if
so, their scope of work.
The Board appointed Guerdon Associates to provide remuneration advice to the Board and Remuneration Committee for the July 2019
review. The works undertaken were limited to market reviews of executive remuneration, but the reports received did not include any
specific recommendations as to the elements or amounts of Key Management Personnel remuneration.
No remuneration consultants were engaged for the July 2020 review of remuneration. Guerdon Associates were engaged to provide advice
relating to the award of the FY2020 STIP, but they did not provide any specific remuneration recommendation.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
31
REMUNERATION REPORT
(AUDITED)
E. Long Term Incentive Plan – Employee Rights Plan (LTIP)
The LTIP is a major component of executive incentives and, in developing the Employee Rights Plan, the Board focused on creating strong
linkages between shareholder value as measured by shareholder returns and executive remuneration. Consequently, vesting conditions
are weighted equally between relative shareholder return and absolute shareholder return. In doing this the Board has identified that it is
not sufficient for Central to perform above its peer group for executives to receive their maximum entitlement to share rights but also to
achieve levels of absolute share price growth that would be considered as superior returns. For example, for the absolute share price
vesting condition to be met, the Central share price must increase by at least 25% per annum for three years, compound growth of 95%.
Key terms and vesting conditions
On 14 November 2018, shareholders re-approved the Company’s LTIP to incentivise eligible employees (Non-Executive Directors are not
eligible to participate in the LTIP).
The maximum number of performance rights vested in any year is determined by measuring Central’s share price performance over that
year compared to a peer group of companies (relative measure) and compared to its absolute share price movement over a three-year
cycle.
The following table details the percentage of Share Rights in respect of the three-year performance period ending 30 June 2020 which will
vest (Vesting Percentage) as determined by the performance conditions, based on the 20-day VWAP prior to 30 June 2020 of $0.0882:
Hurdle
Definition
Hurdle Banding
Vesting
Percentage
Result for Plan
Year Vesting
30 June 2020
Absolute TSR1 growth
(50% weighting)
Company's absolute TSR calculated as at
vesting date. This looks to align eligible
employees’ rewards to shareholder
superior returns
Company’s Absolute TSR
over 3 years
Share Rights
Vesting
25% pa plus
20% to <25% pa
15% to <20% pa
10% to <15% pa
Below 10% pa
100%
75%
50%
25%
0%
Hurdle
Definition
Hurdle Banding
Relative TSR – E&P2
(50% weighting)
Company's TSR relative to a specific
group of exploration and production
companies (determined by the Board
within its discretion) calculated as at
vesting date
Company’s Relative TSR
76th percentile and above
100%
52nd to 75th percentile
51% to 99%
51st percentile
Below 51st percentile
50%
0%
Result for Plan
Year Vesting
30 June 2020
Vesting
Percentage
Share Rights
Vesting
1 Total shareholder return (i.e. growth in share price plus dividends reinvested).
2 Exploration and Production.
For the purposes of determining the maximum number of unvested Share Rights available for vesting, the Company will calculate the
Company’s absolute TSR (total shareholder return as measured by an independent company chosen by the Board) and relative TSR
effective as at the vesting date in accordance with the above table to determine the relative hurdle band and Vesting Percentage met. The
unvested Share Rights for the applicable hurdle for the performance period are then multiplied by the Vesting Percentage achieved for that
hurdle to determine the total number of Share Rights which vest on the vesting date. Vested Share Rights may then be exercised in
accordance with the Employee Rights Plan Rules.
Each vested Share Right can be exercised at the rate of one Share Right for one Ordinary Share in the Company.
Employees must be employed by the Company at the end of the performance period in order for the Share Rights to vest. The maximum
number of Share Rights that an employee is granted is a function of the employee’s base salary, their LTIP percentage, and the 20 trading
days daily volume weighted average sale price of company shares sold on the ASX ending on the trading day prior to the start of the
performance period.
32
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
E. Long Term Incentive Plan – Employee Rights Plan (LTIP) (continued)
If the Company is subject to a Change of Control Event, all unvested Share Rights will immediately vest at 100%, with any performance
criteria being waived.
Details of the LTIP Plan’s key terms can be viewed on the Company’s website at www.centralpetroleum.com.au/careers/why-work-for-
central.
This LTIP provides coverage for various levels of eligible employees which include:
a.
The Managing Director who is principally responsible for achievement of Central’s strategy:
i)
ii)
Up until FY2019 may receive a LTIP percentage up to 50%, subject to shareholder approval; and
From FY2020 participated in the ESOP;
b. The Executive Management Team (EMT) and eligible employees are those in roles which influence and drive the strategic
direction of the Company’s business. EMT eligible employees receive a LTIP percentage up to 30%, with certain EMT participating
in only the ESOP from FY2020;
c.
Eligible employees who are senior managers with responsibility for one or more defined functions, departments or outcomes.
They are more likely to be involved in a balance of strategic and operational aspects of management. Some decision-making at
this level would require approval from the EMT. These eligible employees receive a LTIP percentage up to 20%;
d. Eligible employees who are not part of the EMT and are in roles which are focused on the key drivers of the operational parts of
the Company’s business. These eligible employees receive a LTIP percentage up to 10%; and
e. All other eligible employees are integral to the success of the Company obtaining its goals and objectives may participate in the
Central Petroleum $1,000.00 Exempt Plan.
Conditions of the Central Petroleum $1,000.00 Exempt Plan include:
1.
Share Rights can only be dealt with upon vesting at the end of the three-year service period; and
2. No performance conditions apply.
F. Long Term Incentive Plan – Executive Share Option Plan (ESOP)
On 9 August 2019, the Board resolved to establish an ESOP for certain key executives, and it was approved by shareholders on 7 November
2019. The ESOP replaces the existing LTIP for participating executives and any Share Options granted under the ESOP will replace the Share
Rights that would otherwise have been granted over the next three years under the LTIP. The strike price for each Share Option was set at
$0.20 with an expiry date of 30 June 2023.
Key terms and vesting conditions
Each Share Option entitles the participant to subscribe for one Share upon exercise of the Share Option. Share Options will be issued for no
consideration, unless otherwise determined by the Board. Share Options do not give any rights to participate in dividends nor to
participate in any pro rata issue of securities to Shareholders. The Board may, in its absolute discretion, prescribe service or performance
conditions that must be satisfied as a condition for all or any of the Share Options to be exercised.
The exercise price of the Share Options is determined by the Board. The amount payable upon exercise of each Share Option issued in 2019
is $0.20 (Exercise Price). The Share Options are exercisable from 1 July 2022 until their Expiry Date, 30 June 2023. Once a Share Option is
capable of exercise, it may be exercised at any time up until the Expiry Date. Share Options not exercised before the Expiry Date will
automatically lapse.
Shares issued on exercise of the Share Options rank equally with the then issued shares of the Company.
All Share Options become exercisable if the Company is subject to a change of control event and in the event that the Share Options have
not been exercised before a scheme of arrangement record date or issue of compulsory acquisition notice in the case of a takeover, the
Company will cancel the Share Options and pay a settlement fee to the participant of the greater of 5 cents per Share Option or an amount
equal to the consideration offered under the scheme of arrangement or takeover bid minus the Exercise Price.
All of a participant's Share Options will lapse on the earliest to occur of:
(i)
(ii)
the Expiry Date (as stipulated in the offer); or
unless otherwise stated in the offer, the date that the Board determines that any service or performance conditions stipulated in
the offer as applying to the Share Options cannot be met.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
33
REMUNERATION REPORT
(AUDITED)
F. Long Term Incentive Plan – Executive Share Option Plan (ESOP) (continued)
A participant's Share Options will lapse if a Participant ceases to be an employee, except in certain circumstances at the Board’s discretion.
The number of Share Options which will lapse is a function of the number of days between 1 July 2019 and the participant's termination
date as a proportion of the total days between 1 July 2019 and 1 July 2022.
Unless otherwise determined by the Board, a Share Option will immediately lapse if the participant purports to transfer, assign, mortgage,
charge, encumber sell or otherwise dispose of the Share Option.
G. Short Term Incentive Plan (STIP)
The Short Term Incentive Plan (STIP) is a performance based plan comprising a matrix of Corporate, Departmental and Individual Key
Performance Indicators (KPIs) for all eligible employees.
It is the responsibility of the Board to set the strategic direction priorities and objectives of the Company. The existence of this STIP does
not amend or take away that responsibility and, as such, the results of the STIP form part of the Board’s deliberation in its decision on the
bonus recommendation to be awarded.
The Company’s Board of Directors determine the maximum amount of STIP achievable in any year (normally expressed as a percentage of
base salary). Achieving the maximum is contingent upon all of the KPIs in the matrix being met at the 100% level. The KPIs are reviewed at
the beginning of each year and adjusted where necessary to reflect Central’s strategic direction, the practice in the marketplace and any
other factors which the Board deems relevant. 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. Consistent with the Directors’ focus on appreciation in shareholder value
as the major form of incentive, STIP payments are currently limited to a maximum of 10% of base salary.
Key terms and conditions
The Financial Year 2020 STIP (FY2020 STIP) has been holistically designed to recognise and reward individual effort through connecting
individual KPIs, departmental KPIs and corporate KPIs. These groups of KPIs are intrinsically linked and start by cascading from the
corporate KPIs, to the departmental KPIs and then onto individual KPIs. Individual KPIs drive the success of achieving departmental KPIs,
which are in turn aimed at effecting the desired outcome to be reached in the corporate KPIs.
Participation in this STIP, or the provision of any Company security, does not form part of the participating employee's remuneration for
the purposes of determining payments in lieu of notice of termination of employment, severance payments, leave entitlements, or any
other compensation payable to a participating employee upon the termination of employment (unless the Board otherwise determines).
KPI Category
Executive All Other Employees
Percent Allocation of STIP
Corporate KPIs
Safety and Environment KPI’s
Departmental KPIs
Individual KPIs
30%
10%
40%
20%
Corporate KPIs for FY2020 included:
30%
10%
30%
30%
Objective
Weighting
Exploration
Complete exploration portfolio review in order
to identify prioritised activities and progress an
approved exploration programme
Gas Revenue
Refinancing
Reserve Replacement
Reserves adjusted for production
Total Cost1
Total company operating and capital
expenditure for agreed scope of works
20%
20%
20%
20%
20%
Performance Outcome for FY2020
0%
50%
75%
100%
1 Not rewarded for works that were essential but not completed e.g. capital project delay or deferral
34
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
G. Short Term Incentive Plan (STIP) (continued)
Safety and Environment KPIs for FY2020 included:
Objective
Weighting
Traditional Owner cultural heritage
*Safety: Total Recordable Incident Frequency Rate
(TRIFR)
Safety: (incident reporting & action close-out)
Environment: Recordable environmental incidents
Alice Springs local and Indigenous employment
20%
15%
15%
30%
20%
Performance Outcome for FY2020
0%
50%
75%
100%
Summary Performance of Company-wide KPI’s
Corporate
Safety and Environment
Total
Maximum
30% of STI
10% of STI
40% of STI
FY2020 Outcome
55%
(or 16.5 out of a possible 30)
85%
(or 8.5 out of a possible 10)
62.5%
(or 25 out of a possible 40)
The departmental KPIs vary from one department to the next, however, all are equally important to achieve in the pursuit of achieving
100% of the corporate KPIs which are re-set annually. Departmental KPIs for FY2020 were assessed as achieving 69% on average.
Individual KPIs are linked to the departmental KPIs and as such provide significant relevance to each role in each department and for
FY2020 were assessed as achieving an average of 80%.
The FY2020 STIP percentage allocation is a maximum of up to 10% of the employee’s Base Salary. Notwithstanding difficult business
conditions in CY2020, after assessment of the achievement of the KPIs above, eligible employees were entitled to receive, on average,
69.7% of their maximum STIP bonus.
After considering the Company’s overall performance during the year, cash flow constraints and adverse market conditions caused by the
COVID-19 pandemic, the Board decided that Key Management Personnel (KMP) and those managers that report directly to them would
receive their STIP entitlement in the form of share rights, which only vest after another 3-years of service.
In addition to preserving cash reserves for growth, this will further align senior management with shareholders and provide a retention
incentive as Central embarks on several growth initiatives.
Details of remuneration for the Directors and key management personnel of Central Petroleum Limited and the Consolidated Entity are set
out in section I of this report.
H. Realised Remuneration
Table 1 identifies the Actual Remuneration received by Senior Executives in respect of the financial year. Realised Remuneration reflects
the take home remuneration of the Executive and includes:
•
•
•
•
Total fixed remuneration inclusive of company superannuation contributions;
Any Short Term Incentive awarded as cash for the financial year but paid after the end of the financial year;
Any Short Term Incentive awarded as share rights in lieu of cash for the financial year, and granted after the end of the financial
year valued at the cash equivalent amount (but excluding any share rights which do not immediately vest); and
The value of LTIP share rights vesting (if any) in respect of the three-year period ending 30 June, valued at the year-end share
price (2020: 8.1 cents per share, 2019: 14 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.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
35
REMUNERATION REPORT
(AUDITED)
H. Realised Remuneration (continued)
Table 1: Realised Remuneration
Year
Total Fixed
Remuneration1
$
STI (Cash)
$
GAP Bonus
(Cash) 2
$
Other
Benefits3
$
STI Vested
as Shares4
$
LTI Vested
as Shares5
$
Current Executive KMP
Leon Devaney
Ross Evans
Damian Galvin6
Duncan Lockhart7
Robin Polson
Daniel White
Total Executive KMP
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
612,061
565,939
500,404
423,552
289,162
—
400,472
93,189
335,132
331,400
444,080
438,064
2,581,311
1,852,144
—
49,162
—
20,000
—
—
—
—
—
13,433
—
16,909
—
99,504
—
41,600
—
30,000
—
—
—
—
—
24,400
—
—
—
96,000
8,380
5,159
8,380
3,896
7,039
—
8,332
—
8,380
4,293
8,380
5,159
48,891
18,507
—
—
—
150,917
—
—
—
—
—
—
—
—
—
148,401
—
20,000
—
—
—
—
—
13,433
—
16,909
—
50,342
Total
$
620,441
812,777
508,784
497,448
296,201
—
408,804
93,189
343,512
386,959
452,460
625,442
—
299,318
2,630,202
2,415,815
1 Total Fixed Remuneration includes salaries, fees and superannuation contributions.
2 Discretionary bonus in respect of the Gas Acceleration Project.
3 Includes car parking and other fringe benefits.
4 Short term incentive issued as share rights after year end which vest immediately, valued at cash equivalent STI.
5 Long Term Incentive Vested as Shares comprises any LTI from prior years that was awarded or is expected to be awarded for the three-year period ending 30 June
and valued at that date.
6 Damian Galvin commenced 5 August 2019.
7 Duncan Lockhart commenced 8 April 2019.
36
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
I. Remuneration Details – Statutory tables
Table 2: Remuneration of Directors and Key Management Personnel
Short-Term
Post-Employment
Long-
Term
Benefits
Share-
Based
Payments
Salary/
Fees
$
Non-
Monetary
Benefits1
$
STI1
$
Superannuation
Contributions
Termination
Benefits
LSL
(Accrued)
Rights &
Options2
$
$
$
$
8,194
4,478
7,752
—
14,250
10,806
8,550
4,478
296
—
2,533
15,936
—
5,067
—
5,265
—
1,900
41,575
47,930
21,003
22,765
21,003
22,765
19,779
—
21,003
5,133
21,003
26,508
21,003
24,139
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
12,688
20,947
6,710
5,361
2,920
—
4,073
936
4,534
3,553
9,180
9,855
219,916
76,358
176,225
23,221
99,694
—
120,841
—
120,219
17,746
109,385
124,249
Non-Executive Directors
Stuart Baker3
2020
2019
Julian Fowles4
Wrixon Gasteen5
2020
2019
2020
2019
Katherine Hirschfeld3 2020
2019
Agu Kantsler6
2020
2019
Former Non-Executive Directors
Martin Kriewaldt7
Peter Moore8
Sarah Ryan8
Timothy Woodall9
Sub-total
Executives
Leon Devaney
Ross Evans
Damian Galvin10
Duncan Lockhart11
Robin Polson
Daniel White
Former Executives
Richard Cottee12
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
Michael Herrington13 2020
2019
86,250
47,139
81,604
—
150,000
113,750
90,000
47,139
3,111
—
26,667
167,746
—
53,333
—
55,417
—
20,000
437,632
504,524
601,381
551,385
485,955
410,613
277,551
—
384,464
94,830
329,546
307,387
430,904
418,188
—
314,975
—
257,419
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
10,941
90,762
8,945
70,000
5,363
—
6,708
—
5,446
51,266
7,216
15,918
—
—
—
—
Sub-total
2020
2019
2,509,801
44,619
2,354,797 227,946
Total Remuneration 2020
2019
2,947,433
44,619
2,859,321 227,946
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
8,380
5,159
8,380
3,896
7,039
—
8,332
—
8,380
4,293
8,380
5,159
—
10,105
—
4,668
48,891
33,280
48,891
33,280
Total
$
94,444
51,617
89,356
—
164,250
124,556
98,550
51,617
3,407
—
29,200
183,682
—
58,400
—
60,682
—
21,900
479,207
552,454
874,309
767,376
707,218
535,856
412,346
—
545,421
100,899
489,128
410,753
586,068
597,508
Variable
Remuneration
Percent of
Remuneration
%
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
26%
22%
26%
17%
25%
N/A
23%
—
26%
17%
20%
23%
N/A
N/A
N/A
24%
25%
8%
22%
6%
—
15,005
—
15,292
124,794
131,607
166,369
179,537
—
52,542
—
28,366
—
80,908
—
80,908
—
(68,772)
—
(343,827)
—
(53,199)
40,105
(81,319)
40,105
(81,319)
—
80,865
846,280
(21,388)
846,280
(21,388)
—
(19,972)
—
333,411
3,614,490
2,725,831
4,093,697
3,278,285
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
37
REMUNERATION REPORT
(AUDITED)
I. Remuneration Details – Statutory tables (continued)
Table 2: Remuneration of Directors and Key Management Personnel (continued)
1 Short term incentives are unpaid at the end of the financial year. Amounts are shown in respect of the performance period to which they relate. Subsequent to the
end of the financial year, the Board decided that the 2020 STI is to be awarded as deferred share rights which are expensed over the performance period, which
includes the year to which the bonus relates and the subsequent 3 year vesting period. The value shown is based on the fair value as at 30 June 2020 and will be
subsequently adjusted to the fair value on the actual grant date. The 2019 STI was subsequently settled partly in cash and partly in equity after year end.
2 The fair values of share rights granted are valued using methodology that takes into account market and peer performance hurdles. The values of rights are calculated
at the date of grant using a Black Scholes valuation model and Monte Carlo simulations and an agreed comparator group to assess relative total shareholder return. The
values are allocated to each reporting period evenly over the period from grant date to vesting date. In the event that rights are cancelled for failure to meet the required
service period or are not retained on termination of employment, any amounts previously expensed as share based payments are reversed as negative amounts.
3 Stuart Baker and Katherine Hirschfeld AM were appointed 7 December 2018.
4 Julian Fowles was appointed 28 June 2019.
5 Wrix Gasteen assumed the role of Chairman from 2 September 2019.
6 Agu Kantsler was appointed 15 June 2020.
7 Martin Kriewaldt resigned 2 September 2019.
8 Peter Moore and Sarah Ryan resigned 13 November 2018.
9 Timothy Woodall resigned 29 September 2018.
10 Damian Galvin commenced 5 August 2019.
11 Duncan Lockhart commenced 8 April 2019.
12 Richard Cottee ceased employment effective 31 January 2019.
13 Michael Herrington ceased employment effective 29 January 2019.
The following factors and assumptions were used in determining the fair value of rights granted to key management personnel during FY2020:
Grant Date
Expiry Date
09 Aug 20191
23 Aug 20192
13 Sep 20193
07 Nov 20194
13 Sep 2024
30 Jun 2024
08 Dec 2022
12 Nov 2024
Fair Value
Per Right
Exercise
Price
Price of Shares
at Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
$0.155
$0.155
$0.150
$0.119
Nil
Nil
Nil
Nil
$0.155
$0.190
$0.200
$0.170
N/A
98%
N/A
95%
N/A
0.70%
N/A
0.94%
—
—
—
—
1 STIP Rights fully vested on issue – valued at market price at grant date.
2 LTIP Rights for plan year commencing 1 July 2019.
3 Adjustment to number of LTIP Rights for plan year commencing 1 July 2016 – valued at the market price of the known vesting %.
4 LTIP rights issued to L Devaney in respect of the plan year commencing 1 July 2018.
The following factors and assumptions were used in determining the fair value of share rights granted during FY2019:
Grant Date
Expiry Date
24 Sep 2018
02 Oct 20181
22 Mar 20192
22 May 2024
Various
10 Apr 2024
Fair Value
Per Right
Exercise
Price
Price of Shares
at Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
$0.087
$0.067
$0.130
Nil
Nil
Nil
$0.120
$0.135
$0.130
86%
N/A
N/A
2.33%
N/A
N/A
—
—
—
1 Adjustment to number of LTIP Rights for plan year commencing 1 July 2015 – valued at the market price of the known vesting %.
2 STIP Rights fully vested on issue – valued at market price on issue.
Table 3: Short Term Incentives Awarded
Maximum
$
Awarded1,2
$
Awarded1
%
Forfeited
%
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson
Daniel White
Total
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
61,206
99,547
50,040
77,000
33,000
—
40,047
—
33,513
55,197
44,408
41,765
262,214
273,509
43,762
90,762
35,779
70,000
21,450
—
26,832
—
21,784
51,266
28,865
33,818
178,472
245,846
71%
91%
72%
91%
65%
N/A
67%
N/A
65%
93%
65%
81%
68%
90%
29%
9%
28%
9%
35%
N/A
35%
N/A
35%
7%
35%
19%
32%
10%
1 It was subsequently decided that the FY2020 STIP would be settled in the form of share rights with a further 3-year vesting period. Nil% had vested at 30 June 2020.
2 The FY2019 annual STIP was subsequently settled partly in cash and partly in equity. FY2019 also included a GAP Bonus, as shown in Table 1.
38
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
I. Remuneration Details – Statutory tables (continued)
Table 4: Share Based Compensation – Share Rights Granted to Key Management Personnel during the Year
Number of
Rights Granted
Grant Date
Average
Fair Value at
Grant Date
Average
Exercise Price
Per Right
Expiry Date
Richard Cottee1
Leon Devaney
Ross Evans
Michael Herrington2
Robin Polson
Daniel White
Total
2020
2019
2020
2019
2020
2019
2020
2019
2019
2020
2019
2020
2020
2020
2019
2019
2019
2020
2019
—
02 Oct 18
07 Nov 19
02 Oct 18
09 Aug 19
24 Sep 18
—
24 Sep 18
02 Oct 18
09 Aug 19
24 Sep 18
09 Aug 19
13 Sep 19
23 Aug 19
24 Sep 18
22 Mar 19
02 Oct 18
—
183,540
1,837,109
75,089
140,845
778,854
—
891,413
89,187
94,598
603,491
119,077
123,679
983,204
804,984
83,464
73,843
3,298,512
3,583,865
—
$0.067
$0.119
$0.067
$0.142
$0.087
—
$0.087
$0.067
$0.142
$0.087
$0.142
$0.150
$0.155
$0.087
$0.130
$0.067
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
09 Feb 21
12 Nov 24
05 Jan 21
13-Sep-24
22 May 24
—
22 May 24
05 Jan 21
13-Sep-24
22 May 24
13-Sep-24
08-Dec-22
30-Jun-24
22 May 24
10 Apr 24
05 Jan 21
1 Richard Cottee ceased employment effective 31 January 2019.
2 Michael Herrington ceased employment effective 29 January 2019.
Table 5: Share Based Compensation – Share Rights Vested to Key Management Personnel during the Year
Richard Cottee3
Leon Devaney
Ross Evans
Michael Herrington4
Robin Polson
Daniel White
Total
Maximum
Number of
Rights Eligible
for Vesting
LTIP Year
Commencing
STIP Year
Commencing
Number of
Rights
2Vested1
Proportion of
LTIP Rights
Vested2
Proportion of
LTIP Rights
Forfeited
N/A
2,097,413
1,437,308
858,089
140,845
—
N/A
1,019,187
94,598
—
1,413,345
119,077
843,843
83,464
3,205,173
4,901,996
—
01 Jul 15
01 Jul 16
01 Jul 15
N/A5
—
—
01 Jul 15
N/A5
—
01 Jul 16
N/A5
01 Jul 15
N/A
—
N/A
N/A
N/A
01 Jul 18
—
—
N/A
01 Jul 18
—
N/A
01 Jul 18
N/A
01 Jul 17
—
1,038,219
1,077,981
424,754
140,845
—
—
504,497
94,598
—
1,060,008
119,077
417,702
83,464
2,492,509
2,468,636
—
49.5%
75.0%
49.5%
N/A5
—
—
49.5%
N/A5
—
75.0%
N/A5
49.5%
N/A
75.0%
49.5%
—
50.5%
25.0%
50.5%
N/A5
—
—
50.5%
N/A5
—
25.0%
N/A5
50.5%
N/A
25.0%
50.5%
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2020
2019
2019
2020
2019
1 The number of rights that vested during the year relates to rights granted in prior financial years under the Long Term Incentive Plan or rights granted in respect of
the Short Term Incentive Plan for the year ended 30 June 2019.
2 The proportion of rights vested represents the proportion of the maximum number of rights that were eligible for vesting during the financial year under the Long
Term Incentive Plan. All rights awarded under the Short Term Incentive Plan in respect of the years commencing 1 July 2017 and 1 July 2018 vested on grant date.
3 Richard Cottee ceased employment effective 31 January 2019.
4 Michael Herrington ceased employment effective 29 January 2019.
5 Rights issued as part settlement of FY2019 STIP.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
39
REMUNERATION REPORT
(AUDITED)
I. Remuneration Details – Statutory tables (continued)
Table 6: Share Based Compensation – Options Granted to Key Management Personnel during the Year
Number of
Options Granted
Grant Date
Option
Expiry Date
Exercise
Price
Fair Value
at Grant
Leon Devaney
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson
Total
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
5,105,000
—
4,170,025
—
2,750,000
—
3,333,333
—
2,792,758
—
18,151,116
—
07 Nov 19
—
20 Aug 19
—
20 Aug 19
—
20 Aug 19
—
20 Aug 19
—
30 Jun 23
—
30 Jun 23
—
30 Jun 23
—
30 Jun 23
—
30 Jun 23
—
$0.20
—
$0.20
—
$0.20
—
$0.20
—
$0.20
—
$0.087
—
$0.120
—
$0.120
—
$0.120
—
$0.120
—
The values of Options are calculated at the date of grant using a Black Scholes valuation. The following factors and assumptions were used
in determining the fair value of Options granted to key management personnel during FY2020:
Grant Date
Expiry Date
20 Aug 2019
07 Nov 2019
30 Jun 2023
30 Jun 2023
Fair Value
Per Right
Exercise
Price
Price of
Shares at
Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
$0.120
$0.087
$0.20
$0.20
$0.16
$0.17
78%
78%
0.92%
0.85%
—
—
Share, Rights and Option Holdings of Key Management Personnel
Under the Group’s Long Term Incentive Plans, eligible employees may receive:
a) Rights to shares of the Company under the Employee Rights Plan (refer section E of this report); and
b) Options over shares of the Company under the Executive Share Option Plan (refer section F of this report).
Table 7: Vesting profile of Share Rights Holdings of Key Management Personnel
Leon Devaney
Grant Date Type
1 Sep 2017 Share Rights – LTIP
27 Jun 2018 Share Rights – LTIP
7 Nov 2019 Share Rights – LTIP
Deferred Share Rights – STIP3
Ross Evans
24 Sep 2018 Share Rights – LTIP
9 May 2019 Share Rights – LTIP
Deferred Share Rights – STIP3
Deferred Share Rights – STIP3
Deferred Share Rights – STIP3
24 Sep 2018 Share Rights – LTIP
9 May 2019 Share Rights – LTIP
Deferred Share Rights – STIP3
1 Sep 2017 Share Rights – LTIP
24 Sep 2018 Share Rights – LTIP
9 May 2019 Share Rights – LTIP
23 Aug 2019 Share Rights – LTIP
Deferred Share Rights – STIP3
Damian Galvin
Duncan Lockhart
Robin Polson
Daniel White
Total
Maximum
Number of
Rights Eligible
for Vesting at
30 June 2020
754,705
135,920
1,837,109
642,988
135,866
551,132
52,359
736,319
735,145
69,839
983,204
6,634,586
Vesting
Date1
30 Jun 2020
30 Jun 2020
30 Jun 2021
30 Jun 2023
30 Jun 2021
30 Jun 2023
30 Jun 2023
30 Jun 2023
30 Jun 2023
30 Jun 2021
30 Jun 2021
30 Jun 2023
30 Jun 2020
30 Jun 2021
30 Jun 2021
30 Jun 2022
30 Jun 2023
Maximum value yet to vest2
FY2020 FY2021 FY2022 FY2023
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
132,550
—
18,647
4,574
—
—
—
15,983
1,763
—
—
21,319
2,351
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
106,663
—
—
—
—
32,822
—
—
26,834
16,088
20,124
—
—
16,338
—
—
—
—
21,649
197,187
106,663
133,855
1 The earliest vesting date under the relevant plan rules. The final vesting date may be subject to retesting periods, subject to Board discretion.
2 The maximum value of the share rights yet to vest has been determined as the amount of the grant date fair value of the rights that is yet to be expensed. The
minimum value to vest is nil, as the rights will be forfeited if the vesting conditions are not met.
3 The FY2020 STIP will be awarded as rights to deferred shares instead of cash. The grant date and final number of rights are yet to be determined. The maximum
value of these rights yet to vest is calculated as the estimated fair value as at 30 June 2020 and will be adjusted to the fair value at the grant date once granted.
40
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
I. Remuneration Details – Statutory tables (continued)
The maximum number of rights to ordinary shares in the Company under the long term incentive plan held during the financial year by
other key management personnel of the Consolidated Entity, including their personally related parties, are set out below:
Table 8: Share Rights Holdings of Key Management Personnel
Share Rights
Key Management Personnel
Richard Cottee1
Leon Devaney
Ross Evans
Michael Herrington2
Robin Polson
Daniel White
Total
Number of
Rights Held at
Start of Year
Maximum
Number
Granted as
Compensation
Cancelled
During the
Year
Converted to
Shares
Retained on
Departure
Number of
Rights Held at
End of Year
(Unvested)
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
N/A
6,952,766
2,202,158
2,985,158
778,854
—
N/A
3,380,501
603,491
—
2,830,969
2,795,985
6,415,472
16,114,410
—
183,540
—
(6,098,087)
—
—
N/A
1,038,219
1,837,109
75,089
(233,552)
(433,335)
(1,077,981)
(424,754)
140,845
778,854
—
980,600
94,598
603,491
—
—
—
(1,870,478)
—
—
1,225,960
962,291
3,298,512
3,583,865
(353,337)
(426,141)
(586,889)
(8,828,041)
(140,845)
—
—
(504,497)
(94,598)
—
(1,179,085)
(501,166)
(2,492,509)
(1,430,417)
N/A
N/A
N/A
N/A
N/A
1,986,126
N/A
N/A
N/A
N/A
—
3,024,345
N/A
N/A
2,727,734
2,202,158
778,854
778,854
N/A
N/A
603,491
603,491
2,524,507
2,830,969
6,634,586
6,415,472
1 Richard Cottee ceased employment effective 31 January 2019.
2 Michael Herrington ceased employment effective 29 January 2019.
The number of Options to ordinary shares in the Company under the Executive Share Option Plan held during the financial year by key
management personnel of the Consolidated Entity, including their personally related parties, are set out below:
Table 9: Options Holdings of Key Management Personnel
Share Options
Key Management Personnel
2020
Leon Devaney
2019
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson
Total
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
Number of
Options Held
at Start of
Year
Options
Granted as
Compensation
Exercise
Price
Expiry
Date
Cancelled or
Expired
During the
Year
Exercised and
Converted to
Shares
Number of
Options Held
at End of Year
(Unvested)
Retained on
Departure
—
—
—
—
—
—
—
—
—
—
—
—
5,105,000
—
4,170,025
—
2,750,000
—
3,333,333
—
2,792,758
—
18,151,116
—
30 Jun 23
30 Jun 23
30 Jun 23
30 Jun 23
30 Jun 23
$0.20
—
$0.20
—
$0.20
—
$0.20
—
$0.20
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
—
—
5,105,000
—
4,170,025
—
2,750,000
—
3,333,333
—
2,792,758
—
18,151,116
—
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
41
REMUNERATION REPORT
(AUDITED)
I. Remuneration Details – Statutory tables (continued)
Table 10: Shareholdings of Key Management Personnel
Held at
Beginning of
Year
Held at
Date of
Appointment
SPP & On
Market
Purchase
Exercise of
Rights
Net
Change
Other
Held at
Date of
Departure
Held at
End of
Year
Ordinary Shares
Execu(cid:415)ve Directors
Stuart Baker1
Julian Fowles2
Wrixon Gasteen
2020
2019
2020
2019
2020
2019
Katherine Hirschfeld1 2020
2019
Agu Kantsler3
Martin Kriewaldt4
Peter Moore5
Sarah Ryan5
Timothy Woodall6
Sub-total
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
—
N/A
—
N/A
293,337
293,337
200,000
N/A
N/A
N/A
1,100,000
1,100,000
N/A
265,000
N/A
105,000
N/A
1,500,000
1,593,337
3,263,337
Other Key Management Personnel
Richard Cottee7
2020
2019
N/A
889,933
Leon Devaney
Ross Evans
Damian Galvin8
2020
2019
2020
2019
2020
2019
1,053,776
629,022
—
—
N/A
N/A
Michael Herrington9 2020
2019
N/A
572,564
Duncan Lockhart10
Robin Polson
Daniel White
Sub-total
Total KMP
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
—
N/A
—
—
1,129,989
628,823
2,183,765
2,720,342
3,777,102
5,983,679
N/A
—
N/A
—
N/A
N/A
N/A
200,000
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
—
—
100,000
—
500,000
—
560,850
—
—
—
—
—
—
50,000
—
100,000
—
250,000
—
200,000
1,160,850
400,000
N/A
N/A
N/A
N/A
N/A
N/A
71,000
N/A
N/A
N/A
N/A
—
N/A
N/A
N/A
N/A
—
—
475,000
—
—
—
70,000
—
—
—
—
—
—
—
—
—
71,000
—
71,000
200,000
545,000
—
1,705,850
400,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,077,981
424,754
140,845
—
—
—
—
504,497
—
—
94,598
—
1,179,085
501,166
2,492,509
1,430,417
2,492,509
1,430,417
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
—
—
100,000
—
793,337
293,337
760,850
200,000
—
—
1,100,000
N/A
N/A
1,100,000
N/A
315,000
N/A
205,000
N/A
1,750,000
1,100,000
2,270,000
N/A
N/A
N/A
N/A
N/A
N/A
1,654,187
1,593,337
N/A
N/A
2,606,757
1,053,776
140,845
—
141,000
N/A
N/A
N/A
—
—
94,598
—
2,309,074
1,129,989
5,292,274
2,183,765
6,946,461
3,777,102
—
(47,700)
N/A
842,233
—
—
—
—
—
—
—
—
—
—
—
—
—
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
1,077,061
N/A
N/A
N/A
N/A
N/A
N/A
—
(47,700)
—
(47,700)
—
1,919,294
1,100,000
4,189,294
1 Stuart Baker and Katherine Hirschfeld AM were appointed Directors 7 December 2018.
2 Julian Fowles was appointed Director 28 June 2019.
3 Agu Kantsler was appointed 15 June 2020.
4 Martin Kriewaldt resigned 2 September 2019.
5 Sarah Ryan and Peter Moore resigned 13 November 2018.
6 Timothy Woodall resigned 29 September 2018.
7 Richard Cottee ceased employment effective 31 January 2019.
8 Damian Galvin commenced 5 August 2019.
9 Michael Herrington ceased employment effective 29 January 2019.
10 Duncan Lockhart commenced 8 April 2019.
42
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
J. Executive Service Agreements
The details of service agreements of the key management personnel of the Consolidated Entity are as follows:
Table 11: Key Management Personnel Service Agreements
Name
Position
Leon Devaney
Managing Director & Chief Executive Officer
Ross Evans
Chief Operations Officer
Damian Galvin
Chief Financial Officer
Duncan Lockhart
General Manager Exploration
Robin Polson
Daniel White
Chief Commercial Officer
Group General Counsel & Company Secretary
Term of agreement
expires
Total Annual Fixed
Remuneration1
Notice period2
01 Jul 2022
01 Dec 2022
05 Aug 2022
08 Jul 2022
01 Oct 2022
30 Nov 2021
$612,061
$500,403
$330,000
$400,000
$335,131
$444,080
6 months
6 months
6 months
6 months
6 months
3 months
1 Total Annual Fixed Remuneration includes compulsory superannuation contributions.
2 In certain exceptional circumstances (such as breach or gross misconduct) a shorter notice period applies.
K. Non-Executive Director Fee Arrangements
The Company has engaged all Directors pursuant to written service agreements. The terms of appointment are subject to the Company’s
constitution. The Company maintains an appropriate level of Directors’ and Officers’ Liability Insurance and provide rights relating to
indemnity, insurance, and access to documents.
The table below summarises the Non-Executive Director fees for FY2020.
Board Fees (per annum)
Chairman
Non-Executive Director
$130,000
$70,000
FY2020 Committee Fees (per annum)
Audit
Community Affairs
Remuneration & Nominations
Risk
Chair
Member
Chair
Member
Chair
Member
Chair
Member
$10,000
$5,000
$10,000
$5,000
$10,000
$5,000
$10,000
$5,000
In FY2021, there will be three Committees, with Committee Fees as follows:
FY2021 Committee Fees (per annum)
Audit & Financial Risk
Remuneration & Nominations
Risk & Sustainability
Chair
Member
Chair
Member
Chair
Member
$10,000
$5,000
$10,000
$5,000
$10,000
$5,000
The directors also receive superannuation benefits in accordance with legislative requirements.
Signed in accordance with a resolution of the directors:
Wrixon Gasteen
Chairman
24 September 2020
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 43
AUDITOR’S INDEPENDENCE DECLARATION
30 JUNE 2020
Auditor’s Independence Declaration
As lead auditor for the audit of Central Petroleum Limited for the year ended 30 June 2020, 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.
Tim Allman
Partner
PricewaterhouseCoopers
Brisbane
24 September 2020
PricewaterhouseCoopers, ABN 52 780 433 757
480 Queen Street, BRISBANE QLD 4000, GPO Box 150, BRISBANE QLD 4001
T: +61 7 3257 5000, F: +61 7 3257 5999, www.pwc.com.au
Liability limited by a scheme approved under Professional Standards Legislation.
44
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
FINANCIAL REPORT
CONTENTS
FINANCIAL STATEMENTS
Consolidated Statement of Profit or Loss and Other Comprehensive Income .......................... 46
Consolidated Balance Sheet .......................................................................................................................... 47
Consolidated Statement of Changes in Equity ....................................................................................... 48
Consolidated Statement of Cash Flows .................................................................................................... 49
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS ............................................................................. 50
DIRECTORS’ DECLARATION ............................................................................................................................................ 95
INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS ..................................................................................... 96
ASX ADDITIONAL INFORMATION ................................................................................................................................ 103
INTERESTS IN PETROLEUM PERMITS AND PIPELINE LICENCES .................................................................... 105
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 review of operations and
activities on pages 3 to 22. These pages are not part of these financial statements.
The financial statements were authorised for issue by the Directors on 24 September 2020. 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. Press releases, financial reports and
other information are available via the links on our website: www.centralpetroleum.com.au.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 45
CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND
OTHER COMPREHENSIVE INCOME
FOR THE YEAR ENDED 30 JUNE 2020
Revenue from contracts with customers – sale of hydrocarbons
Cost of sales
Gross profit
Other income
Exploration expenditure
Employee benefits and associated costs net of recoveries
Share based employment benefits
General and administrative expenses net of recoveries
Depreciation and amortisation
Impairment expense
Finance costs
Profit/(Loss) before income tax
Income tax (expense)/credit
Profit/(Loss) for the year
Other comprehensive profit/(loss) for the year, net of tax
Total comprehensive profit/(loss) for the year
Total comprehensive profit/(loss) attributable to members of the parent entity
Earnings per share for profit or loss attributable to the ordinary equity
holders of the company:
NOTE
2
3
4(b)
32(d)
4(a)
4(c)
4(a)
5
2020
$’000
65,046
(33,386)
31,660
8,610
(5,277)
(4,512)
(1,937)
(266)
(16,257)
(177)
(6,433)
5,411
—
5,411
—
5,411
5,411
2019
$’000
59,358
(30,369)
28,989
385
(15,802)
(5,194)
(602)
(1,032)
(12,695)
—
(8,575)
(14,526)
—
(14,526)
—
(14,526)
(14,526)
Basic earnings/(loss) per share (cents)
Diluted earnings/(loss) per share (cents)
23
23
0.75
0.75
(2.05)
(2.05)
The accompanying notes form part of these financial statements.
46
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
CONSOLIDATED BALANCE SHEET
AS AT 30 JUNE 2020
NOTE
2020
$’000
2019
$’000
ASSETS
Current assets
Cash and cash equivalents
Trade and other receivables
Inventories
Total current assets
Non-current assets
Property, plant and equipment
Right of use assets
Exploration assets
Intangible assets
Other financial assets
Goodwill
Total non-current assets
Total assets
LIABILITIES
Current liabilities
Trade and other payables
Deferred revenue
Borrowings
Lease liabilities
Other financial liabilities
Provisions
Total current liabilities
Non-current liabilities
Deferred revenue
Borrowings
Lease liabilities
Other financial liabilities
Provisions
Total non-current liabilities
Total liabilities
Net assets
EQUITY
Contributed equity
Reserves
Accumulated losses
Total equity
7
8
9
10
11
12
13
14
15
16
2(b)
17
11
18
19
2(b)
17
11
18
19
25,918
6,774
2,581
35,273
17,806
9,060
2,720
29,586
107,845
123,475
1,059
8,722
312
2,656
3,906
124,500
159,773
5,287
10,891
6,964
608
—
4,774
28,524
22,964
63,809
618
—
42,276
129,667
158,191
1,582
—
8,899
113
2,771
3,906
139,164
168,750
6,006
6,753
10,957
—
2,025
5,376
31,117
15,559
70,773
—
13,824
43,094
143,250
174,367
(5,617)
197,776
25,310
(228,703)
(5,617)
20 (a)
21
22
197,776
27,238
(223,432)
1,582
The accompanying notes form part of these financial statements.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 47
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEAR ENDED 30 JUNE 2020
Contributed
Equity
$’000
Reserves
$’000
Accumulated
Losses
$’000
Balance at 1 July 2018
Total loss for the year
Other comprehensive loss
Total comprehensive loss for the year
Transactions with owners in their capacity
as owners
Share based payments
Options issued for financing
Balance at 30 June 2019
Change in accounting policy (Note 1(aa))
Restated total equity as at 1 July 2019
Total profit for the year
Other comprehensive loss
Total comprehensive loss for the year
Transactions with owners in their capacity
as owners
Share based payments
Share issue costs
197,776
23,464
—
—
—
—
—
—
197,776
—
197,776
—
—
—
—
—
—
—
—
—
602
1,244
1,846
25,310
—
25,310
—
—
—
1,937
(9)
1,928
(214,177)
(14,526)
—
(14,526)
—
—
—
(228,703)
(140)
(228,843)
5,411
—
5,411
—
—
—
Balance at 30 June 2020
197,776
27,238
(223,432)
Total
$’000
7,063
(14,526)
—
(14,526)
602
1,244
1,846
(5,617)
(140)
(5,757)
5,411
—
5,411
1,937
(9)
1,928
1,582
The accompanying notes form part of these financial statements.
48
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED 30 JUNE 2020
NOTE
Cash flows from operating activities
Receipts from customers
Interest received
Other income
Government grants
Interest and borrowing costs
Payments for exploration expenditure
Payments to other suppliers and employees
Net cash inflow from operating activities
28
Cash flows from investing activities
Payments for property, plant and equipment
Proceeds from sale of property, plant and equipment
Proceeds and deposits for the disposal of exploration permits
Redemption/(acquisition) of security deposits and bonds
Net cash inflow/(outflow) from investing activities
Cash flows from financing activities
Payments for the issue of securities
Proceeds from borrowings and other financing arrangements
Repayment of borrowings
Transaction costs related to borrowings
Principal elements of lease payments (2019: Principal elements of finance lease
payments)
Net cash (outflow)/inflow from financing activities
Net increase/(decrease) in cash and cash equivalents
Cash and cash equivalents at the beginning of the financial year
Cash and cash equivalents at the end of the financial year
29
29
7
2020
$’000
62,945
172
6
(133)
(5,089)
(3,142)
(39,032)
15,727
(3,224)
76
7,713
115
4,680
(10)
—
(11,501)
(236)
(548)
(12,295)
8,112
17,806
25,918
2019
$’000
58,924
373
26
—
(6,452)
(18,106)
(32,300)
2,465
(17,481)
—
—
2,098
(15,383)
—
17,500
(13,999)
—
—
3,501
(9,417)
27,223
17,806
The accompanying notes form part of these financial statements.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 49
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The principal accounting policies adopted in the preparation of these consolidated financial statements are set out below. These policies
have been consistently applied to all the years presented, unless otherwise stated. The financial statements are for the consolidated entity
consisting of Central Petroleum Limited (“the Company”) and its subsidiaries (collectively “the Group” or “the Consolidated Entity”).
(a) Basis of Preparation
These general-purpose financial statements have been prepared in accordance with Australian Accounting Standards and Interpretations
issued by the Australian Accounting Standards Board and the Corporations Act 2001. They present reclassified comparative information
where required for consistency with the current year’s presentation or where otherwise stated. Central Petroleum Limited is a for-profit
entity for the purpose of preparing the financial statements.
Rounding of Amounts
The company is of a kind referred to in ASIC Legislative Instrument 2016/191, relating to the ‘rounding off’ of amounts in the financial
statements. Amounts in the financial statements have been rounded off in accordance with the instrument to the nearest thousand
dollars, or in certain cases, the nearest dollar.
(i) Going Concern
The Directors have prepared the financial statements on a going concern basis which contemplates continuity of normal business activities
and the realisation of assets and settlement of liabilities in the normal course of business.
The Group recorded a net profit for the year of $5,411,000, had a net positive cash flow from operations of $15,727,000 and had an overall
net current asset position at 30 June 2020 of $6,749,000. The net current assets include $10,891,000 of deferred revenue which will be
settled via the physical delivery of gas rather than as any cash payment to the customer. The Board and management monitor the Group’s
cash flow requirements to ensure it has sufficient funds to meet its contractual commitments and adjusts its spending, particularly with
respect to discretionary exploration activity and corporate expenditures.
Supported by the cash assets at 30 June 2020 of $25,918,000, and expected operating cashflows, the Group forecasts that over at least the
next 12 months, it will have sufficient funds to meet its commitments and continue to pay its debts as and when they fall due. To date the
Group has been successful in funding new projects through a combination of borrowings, gas presales, farmouts and equity from new and
existing shareholders.
Management and the Board are confident that new financing arrangements will be in place before expiry of the existing loan facility in
September 2021. If the Company’s current process to farm-out (sell-down) an interest in some of its existing assets is successful, it is
expected that a significant portion of the proceeds would be available to retire a portion of outstanding debt and reduce the balance
maturing in September 2021. The Company is considering various refinancing / maturity extension options.
Accordingly, the Directors believe the going concern assumption is appropriate.
(ii) Compliance with IFRS
The consolidated financial statements of the Central Petroleum Limited Group also comply with International Financial Reporting Standards
(IFRS) as issued by the International Accounting Standards Board.
(iii) Early Adoption of Standards
The Group has not applied any pronouncements to the annual reporting period beginning on 1 July 2019 where such application would
result in them being applied prior to them becoming mandatory.
(iv) Historical Cost Convention
These financial statements have been prepared under the historical cost convention.
(v) Critical Accounting Judgements and Key Sources of Estimate Uncertainty
In the application of the Group’s accounting policies, management is required to make judgements, estimates and assumptions regarding
carrying values of assets and liabilities that are not readily apparent from other sources. The estimates and assumptions are based on
historical experience and various other factors that are believed to be reasonable under the circumstances, the results of which form the
basis of making the judgements. Actual results may differ from these estimates. Key judgements in applying the entity’s accounting policies
are required in the following areas:
50
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(a) Basis of Preparation (continued)
(v) Critical Accounting Judgements and Key Sources of Estimate Uncertainty (continued)
Rehabilitation Obligations
The Group recognises any obligations for removal and restoration that are incurred during a particular period as a consequence of having
undertaken exploration and evaluation activity. The Group makes provision for future restoration expenditure relating to work previously
undertaken based on management’s estimation of the work required and by obtaining cost estimates from relevant experts. Further
information on the nature and carrying amount of restoration and rehabilitation obligations can be found in Note 19.
Share-based Payments
The Group is required to use assumptions in respect of its fair value models, and the variable elements in these models, used in attributing
a value to share based payments. The Directors have used a model to value options and rights, which requires estimates and judgements
to quantify the inputs used by the model. Further information on the assumptions used in determining the fair value of rights and options
granted during the year can be found in Section I of the Remuneration Report.
Capitalised Exploration and Evaluation Expenditure
The future recoverability of capitalised exploration and evaluation expenditure is dependent on a number of factors, including whether the
Group decides to exploit the lease itself or, if not, whether it successfully recovers the related exploration and evaluation expenditure
through sale. Factors that impact recoverability may include, but are not limited to, the level of resources and reserves, the cost of
production, regulatory changes and commodity price movements. Acquisition expenditure is capitalised if activities in the area of interest
have not yet reached a stage that permits a reasonable assessment of the existence or otherwise of economically recoverable reserves. To
the extent that the capitalised acquisition expenditure is determined not to be recoverable in future, profits and net assets will be reduced
in the period in which this determination is made. Further information on the carrying value of capitalised exploration and evaluation
expenditure can be found in Note 12.
Other Non-financial Assets
Other non-financial assets, including property, plant and equipment and goodwill are tested for impairment annually or whenever events
or changes in circumstances indicate that the carrying amount may not be recoverable. For the purposes of assessing impairment, assets
are grouped at the lowest levels for which there are separately identifiable cash inflows which are largely independent of the cash inflows
from other assets or groups of assets (cash-generating units). 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.
Other Financial Liabilities
The Group may be required to use assumptions in respect of expected future gas prices in respect of gas sales agreements that contain a
financial settlement option. The expected future financial settlements reference expected future gas sales volumes and prices and the
terms of individual agreements (refer to Note 18 for further details).
Taxation
The Group’s accounting policy for taxation requires management’s judgement in relation to the types of arrangements considered to be a tax
on income in contrast to an operating cost. Judgement is also made in assessing whether deferred tax assets and certain deferred tax liabilities
are recognised on the Consolidated Balance Sheet. Deferred tax assets, including those arising from un-recouped tax losses and capital losses,
are recognised only where it is considered more likely than not they will be recovered, which is dependent on the generation of sufficient
future taxable profits.
Judgements are also required about the application of income tax legislation. These judgements and assumptions are subject to risk and
uncertainty, hence there is a possibility changes in circumstances will alter expectation, which may impact the amount of deferred tax
assets and deferred tax liabilities recognised on the Consolidated Balance Sheet and the amount of other tax losses and temporary
differences not yet recognised. In such circumstances, some or all of the carrying amounts of recognised deferred tax assets and liabilities
may require adjustment, resulting in a corresponding credit or charge to the Consolidated Statement of Profit or Loss and Other
Comprehensive Income.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
51
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(b) Principles of Consolidation
(i)
Subsidiaries
The consolidated financial statements incorporate the assets and liabilities of all subsidiaries of Central Petroleum Limited (“the Company”
or “Parent Entity”) as at 30 June and the results of all subsidiaries for the year then ended. Central Petroleum Limited and its subsidiaries
together are referred to in this financial report as “the Group” or “the Consolidated Entity”.
Subsidiaries are all entities (including structured entities) over which the Group has control. The Group controls an entity when the Group
is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its
power to direct the activities of the entity.
Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated from the date that
control ceases. The acquisition method is used to account for business combinations by the Group.
Intercompany transactions, balances and unrealised gains on transactions between Group entities are eliminated. Unrealised losses are
also eliminated unless the transaction provides evidence of the impairment of the asset transferred. Accounting policies of subsidiaries
have been changed where necessary to ensure consistency with the policies adopted by the Group.
Non-controlling interests (if applicable) in the results and equity of subsidiaries are shown separately in the statement of comprehensive
income, statement of changes in equity and balance sheet respectively.
(ii) Joint Arrangements
The Group’s investments in joint arrangements are classified as either joint operations or joint ventures; depending on the contractual
rights and obligations each investor has, rather than the legal structure of the joint arrangement.
The Group’s exploration and production activities are conducted through joint arrangements governed by joint operating agreements or
similar contractual relationships.
A joint operation involves the joint control, and often the joint ownership, of one or more assets contributed to, or acquired for the
purpose of, the joint operation and dedicated to the purposes of the joint operation. The assets are used to obtain benefits for the parties
to the joint operation. Each party may take a share of the output from the assets and each bears an agreed share of expenses incurred.
Each party has control over its share of future economic benefits through its share of the joint operation. The interests of the Group in joint
operations are brought to account by recognising in the financial statements the Group’s share of jointly controlled assets, share of
expenses and liabilities incurred, and the income from the sale or use of its share of the production of the joint operation in accordance
with the revenue policy in Note 1(e). Details of the joint operations are set out in Note 34.
(c) Segment Reporting
Operating segments are reported in Note 24 in a manner consistent with the internal reporting provided to the chief operating decision
maker. The chief operating decision makers, who are responsible for allocating resources and assessing performance of the operating
segments, have been identified as the Executive Management Team.
(d) Foreign Currency Translation
(i)
Functional and Presentation Currency
Items included in the financial statements of each of the Group’s entities are measured using the currency of the primary economic
environment in which the entity operates (the “functional currency”). The consolidated financial statements are presented in Australian
dollars, which is Central Petroleum Limited’s functional currency and presentation currency.
(ii) Transactions and Balances
Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the
transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end
exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in profit or loss, except when they are
deferred in equity as qualifying cash flow hedges and qualifying net investment hedges or are attributable to part of the net investment in
a foreign operation.
52
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(e) Revenue Recognition
Revenue from contracts with customers is recognised in the income statement when or as the Group transfers control of goods or services
to a customer at the amount to which the Group expects to be entitled. If the consideration promised includes a variable amount, the
Group estimates the amount of consideration to which it will be entitled.
(i) Revenue from the sale of hydrocarbons
Revenue from the sale of hydrocarbons is recognised based on volumes sold under contracts with customers, at the point in time where
performance obligations are considered met. Generally, regarding the sale of hydrocarbon products, the performance obligation will be
met when the product is delivered to the specified measurement point (gas) or point of loading/unloading (liquids).
(ii) Farmouts and terminations
Farmouts outside the exploration phase are accounted for by derecognition of the proportion of the asset disposed of, and recognition of
the consideration received or receivable from the farmee. A gain or loss is recognised for the difference between the net disposal proceeds
and the carrying value of the asset disposed. Consideration is initially recognised at fair value or the cash price equivalent where payment is
deferred. Interest revenue is recognised for the difference between the nominal amount of the consideration and the cash price
equivalent.
Any cash consideration received directly from a farminee in respect of the farmout of an exploration asset is credited against costs
previously capitalised, if applicable, with any excess accounted for as a gain on disposal.
(iii) Contract Liabilities
A contract liability is recorded for obligations under sales contracts to deliver natural gas in future periods for which payment has already
been received (including “take-or-pay” arrangements). The Group applies the practical expedient in paragraph 121 of AASB 15 and does
not disclose information on the transaction price allocated to performance obligations that are unsatisfied.
(iv)
Interest Income
Interest income is recognised on a time proportionate basis that takes into account the effective yield on the financial assets.
(f) Government Grants
Cash grants from the government, including research and development concessions, are recognised at their fair value where there is a
reasonable assurance that the grant or refund will be received, and the Group has or will comply with any conditions attaching to the grant
or refund. Research and development grants are recognised as other income in the profit and loss where they relate to exploration
expenditure which has been expensed in the profit and loss. Grants in the form of wages subsidies are credited against employee costs.
Non-monetary grants are recognised at a nominal amount.
(g)
Income Tax
Central Petroleum Limited and its wholly owned Australian controlled entities have implemented the tax consolidation legislation. The
head entity is Central Petroleum Limited. As a consequence, these entities are taxed as a single entity. The Company and the other entities
in the tax-consolidated group have entered into a tax funding and a tax sharing agreement.
The Group accounts for income taxes in accordance with UIG 1052 adopting the “Separate Taxpayer within Group Approach”.
The income tax expense or revenue for the period is the tax payable on the current period’s taxable income based on the applicable
income tax rate adjusted by changes in deferred tax assets and liabilities attributable to temporary differences. The current income tax
charge is calculated on the basis of the tax laws enacted or substantially enacted at the end of the reporting period in the countries where
entities in the Group generate taxable income.
Each individual entity recognises deferred tax assets and deferred tax liabilities arising from temporary differences on the basis that the
entity is subject to tax as part of the tax-consolidated group. Deferred tax assets are recognised for deductible temporary differences and
unused tax losses only if it is probable that future taxable amounts will be available to utilise those temporary differences and losses. Each
entity assesses the recovery of its unused tax losses and tax credits only in the period in which they arise and before assumption by the
head entity, applied in the context of the Group whether as a reduction of current tax of other entities in the group or as a deferred tax
asset of the head entity. The aggregate amount of losses or credits utilised or recognised as a deferred tax asset by the head entity is
apportioned on a systematic and reasonable basis.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
53
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(g) Income Tax (continued)
Deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill. Deferred tax is also not accounted for if it
arises from initial recognition of an asset or liability in a transaction other than a business combination that, at the time of the transaction,
affects neither accounting nor taxable profit or loss. Deferred income tax is determined using tax rates (and laws) that have been enacted
or substantially enacted by the end of the reporting period and are expected to apply when the related deferred income tax asset is
realised, or the deferred income tax liability is settled.
Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets and liabilities and when the
deferred tax balances relate to the same taxation authority. Current tax assets and tax liabilities are offset where the entity has a legally
enforceable right to offset and intends either to settle on a net basis, or to realise the asset and settle the liability simultaneously.
(h) Leases
The Group has changed its accounting policy for leases where the Group is lessee. The new policy is described in Note 11(c) and the impact
of the change is explained in Note 1(aa).
Until 30 June 2019 all the Group’s leases of property, plant and equipment were classified as operating leases (Note 31(c)). Payments made
under operating leases (net of any incentives received from the lessor) were charged to profit or loss on a straight-line basis over the
period of the lease.
(i)
Impairment of Assets
Goodwill and intangible assets that have an indefinite useful life are not subject to amortisation and are tested annually for impairment, or
more frequently if events or changes in circumstances indicate that they might be impaired. Other assets are tested for impairment
whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised
for the amount by which the asset's carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset's
fair value less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which
there are separately identifiable cash inflows which are largely independent of the cash inflows from other assets or groups of assets (cash-
generating units). Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the impairment
at the end of each reporting period.
(j) Cash and Cash Equivalents
For the purpose of presentation in the statement of cash flows, cash and cash equivalents includes cash on hand, deposits held at call with
financial institutions, other short-term, highly liquid investments with original maturities of 3-months or less that are readily convertible to
known amounts of cash and which are subject to an insignificant risk of changes in value, and bank overdrafts. Bank overdrafts (if
applicable) are shown within borrowings in current liabilities in the balance sheet.
(k) Trade Receivables
Trade receivables are recognised initially at the amount of consideration that is unconditional unless they contain significant financing
components, when they are recognised at fair value. The Group holds the trade receivables with the objective to collect the contractual
cash flows and therefore measures them subsequently at amortised cost using the effective interest method.
The Group considers an allowance for expected credit losses (ECLs) for all receivables. The Group applies a simplified approach in
calculating ECLs which is based on an assessment on its historical credit loss experience, adjusted for factors specific to the debtors and the
economic environment. This includes, but is not limited to, financial difficulties of the debtor, probability that the debtor will enter
bankruptcy or financial reorganisation and delinquency in payments.
Information about the impairment of trade receivables and the Group’s exposure to credit risk, foreign currency risk and interest rate risk
can be found in Note 33.
54
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(l)
Inventories
Inventories comprise hydrocarbon stocks, drilling materials and spare parts and are valued at the lower of cost and net realisable value.
Costs are assigned to individual items of inventory on a first in first out or weighted average cost basis. Cost of inventory includes the
purchase price after deducting any rebates and discounts, as well as any associated freight charges.
Net realisable value is the estimated selling price in the ordinary course of business less the estimated costs necessary to make the sale.
(m) Other Financial Assets
(i) Classification
The Group’s financial assets consist of receivables and security deposits. These are non-derivative financial assets with fixed or
determinable payments that are not quoted in an active market. They are included in current assets, except for those with maturities
greater than 12-months after the reporting period which are classified as non-current assets. Receivables are included in trade and other
receivables (Note 8) in the balance sheet. Amounts paid as performance bonds or amounts held as security for bank guarantees are
classified as other financial assets (Note 14).
(ii) Measurement
At initial recognition, the Group measures a financial asset at its fair value plus, in the case of a financial asset not at fair value through
profit or loss, transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets
carried at fair value through profit or loss are expensed in profit or loss. Loans and receivables are subsequently carried at amortised cost
using the effective interest method.
The Group considers an allowance for expected credit losses (ECLs) for its financial assets. The Group applies a simplified approach in
calculating ECLs which is based on an assessment on its historical credit loss experience, adjusted for factors specific to the counterparty
and the economic environment.
(n) Property, Plant and Equipment – Development and Production Assets
(i) Assets in Development
The costs of oil and gas properties in the development phase are separately accounted for and include costs transferred from exploration
and evaluation assets once technical feasibility and commercial viability of an area of interest are demonstrable. When production
commences, the accumulated costs are transferred to producing areas of interest except for land and buildings and surface plant and
equipment associated with development assets which are recorded in the land and buildings and plant and equipment categories
respectively. Amortisation is not charged on costs carried forward in respect of areas of interest in the development phase until production
commences.
(ii) Producing Assets
The costs of oil and gas properties in production are separately accounted for and include costs transferred from exploration and
evaluation assets, transferred development assets and the ongoing costs of continuing to develop reserves for production including an
estimate of the future costs to restore the site. Land and buildings and surface plant and equipment associated with producing areas of
interest are recorded in the land and buildings and plant and equipment categories respectively.
Depreciation of producing assets is calculated for an asset or group of assets from the date of commencement of production. Depletion
charges are calculated using the units of production method which will amortise the cost of carried forward exploration, evaluation,
subsurface development expenditure (subsurface assets) and capitalised restoration costs over the life of the estimated Proven plus
Probable (2P) hydrocarbon reserves for an asset or group of assets, together with estimated future costs necessary to develop the
hydrocarbon reserves included in the calculation.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
55
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(o) Property, Plant and Equipment – Other than Development and Production
Assets
All property, plant and equipment is stated at historical cost less depreciation. Historical cost includes expenditure that is directly
attributable to the acquisition of the items. Cost may also include transfers from equity of any gains or losses on qualifying cash flow
hedges of foreign currency purchases of property, plant and equipment.
Subsequent costs are included in the asset's carrying amount or recognised as a separate asset, as appropriate, only when it is probable
that future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. The
carrying amount of any component accounted for as a separate asset is derecognised when replaced. All other repairs and maintenance
costs are charged to profit or loss during the reporting period in which they are incurred.
Land is not depreciated. Depreciation of plant and equipment is calculated on a reducing balance basis so as to write off the net costs of
each asset over the expected useful life. The assets' residual values and useful lives are reviewed, and adjusted if appropriate, at each
balance date.
An asset's carrying amount is written down immediately to its recoverable amount if the asset's carrying amount is greater than its
estimated recoverable amount. Gains and losses on disposals are determined by comparing proceeds with the carrying amount. These are
included in the profit or loss.
The expected useful life for each class of depreciable assets is:
Class of Fixed Asset
Expected Useful Life
Buildings
Leasehold Improvements
Plant and Equipment
Motor Vehicles
40 years
2 – 6 years
2 – 30 years
5 – 10 years
(p) Exploration Expenditure
Exploration and evaluation costs are expensed as incurred. Acquisition costs of rights to explore are capitalised in respect of each separate
area of interest and carried forward where: right of tenure of the area of interest is current; these costs are expected to be recouped
through sale or successful development and exploitation of the area of interest; or where exploration and evaluation activities in the area
of interest have not yet reached a stage that permits reasonable assessment of the existence of economically recoverable reserves. No
amortisation is charged on acquisition costs capitalised under this policy.
When an area of interest is abandoned or the Directors decide that it is not commercial, any accumulated costs in respect of that area are
written off in the financial period the decision is made. Each area of interest is also reviewed at the end of each accounting period and
accumulated costs written off to the extent that they will not be recoverable in the future.
(q) Goodwill
Goodwill arising on the acquisition of subsidiaries is not amortised but it is tested for impairment annually, or more frequently if events or
changes in circumstances indicate a potential impairment. Goodwill is carried at cost less accumulated impairment losses.
Goodwill is allocated to cash generating units for the purpose of impairment testing. The allocation is made to those cash-generating units
or groups of cash-generating units that are expected to benefit from the business combination in which the goodwill arose. The units or
groups of units are identified at the lowest level at which goodwill is monitored for internal management purposes, being the operating
segments (Note 24).
(r) Trade and Other Payables
These amounts represent liabilities for goods and services provided to the Group prior to the end of financial year which are unpaid. The
amounts are unsecured and are usually paid within 30 days of recognition, except contributions to Joint Arrangements that are settled in
line with the Joint Operating Agreements. Trade and other payables are presented as current liabilities unless payment is not due within
12-months from the reporting date. They are recognised initially at their fair value and subsequently measured at amortised cost using the
effective interest method.
56
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(s) Provisions
(i) Restoration and Rehabilitation
The Group records the present value of the estimated cost of legal and constructive obligations to restore operating locations in the period
in which the obligation arises. The nature of restoration activities includes the removal of facilities, abandonment of wells and restoration
of affected areas.
A restoration provision is recognised and updated at different stages of the development and construction of a facility and then reviewed
on an annual basis. When the liability is initially recorded, the present value of the estimated future cost is capitalised by increasing the
carrying amount of the related property plant and equipment. Over time, the liability is increased for the change in the present value based
on a pre-tax discount rate appropriate to the risks inherent in the liability. The unwinding of the discount is recorded as an accretion charge
within finance costs.
The carrying amount capitalised in property plant and equipment is depreciated over the useful life of the related producing asset (refer to
Note 1(n)).
Costs incurred that relate to an existing condition caused by past operations and do not have a future economic benefit are expensed.
(ii) Onerous Contracts
An Onerous Contracts provision is recognised where the unavoidable costs of meeting obligations under the contract exceeds the value of
the economic benefits expected to be received under the contract.
(iii) Other
Provisions for legal claims and make good obligations are recognised when the Group has a present legal or constructive obligation as a
result of past events, it is probable that an outflow of resources will be required to settle the obligation and the amount has been reliably
estimated. Provisions are not recognised for future operating losses.
Where there are a number of similar obligations, the likelihood that an outflow will be required in settlement is determined by considering
the class of obligations as a whole. A provision is recognised even if the likelihood of an outflow with respect to any one item included in
the same class of obligations may be small.
Provisions are measured at the present value of management’s best estimate of the expenditure required to settle the present obligation
at the end of the reporting period. The discount rate used to determine the present value is a pre-tax rate that reflects current market
assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is
recognised as accretion expense.
(t) Employee Benefits
(i)
Short-term Obligations
Liabilities for wages and salaries, including non-monetary benefits, annual leave and long service leave expected to be settled within
12-months after the end of the period in which the employees render the related service are recognised in respect of employees' services
up to the end of the reporting period and are measured at the amounts expected to be paid when the liabilities are settled. The liability for
annual leave and long service leave is recognised in the provision for employee benefits. All other short-term employee benefit obligations
are presented as payables.
(ii) Long-term Employee Benefit Obligations
The liability for long service leave which is not expected to be settled within 12-months after the end of the period in which the employees
render the related service is recognised in the provision for employee benefits and measured as the present value of expected future
payments to be made in respect of services provided by employees up to the end of the reporting period. Consideration is given to
expected future wage and salary levels, experience of employee departures and periods of service. Expected future payments are
discounted using market yields at the end of the reporting period with terms to maturity and currency that match, as closely as possible,
the estimated future cash outflows.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
57
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(t) Employee Benefits (continued)
(iii) Share-based Payments
Share-based compensation benefits are provided to employees by Central Petroleum Limited.
The fair value of options or rights granted is recognised as an employee benefits expense with a corresponding increase in equity. The total
amount to be expensed is determined by reference to the fair value of the rights or options granted, which includes any market
performance conditions and the impact of any non-vesting conditions but excludes the impact of any service and non-market performance
vesting conditions.
Non-market vesting conditions are included in assumptions about the number of rights or options that are expected to vest. The total
expense is recognised over the vesting period, which is the period over which all of the specified vesting conditions are to be satisfied. At
the end of each period, the entity revises its estimates of the number of rights or options that are expected to vest based on the non-
market vesting conditions. It recognises the impact of the revision to original estimates, if any, in profit or loss, with a corresponding
adjustment to equity.
(iv) Termination Benefits
Termination benefits are payable when employment is terminated by the Group before the normal retirement date, or when an employee
accepts voluntary redundancy in exchange for these benefits.
The Group recognises termination benefits at the earlier of the following dates: (a) when the Group can no longer withdraw the offer of
those benefits; and (b) when the entity recognises costs for a restructuring that is within the scope of AASB 137 and involves the payment
of terminations benefits. In the case of an offer made to encourage voluntary redundancy, the termination benefits are measured based on
the number of employees expected to accept the offer. Benefits falling due more than 12-months after the end of the reporting period are
discounted to present value.
(u) Contributed Equity
Ordinary shares are classified as equity.
Incremental costs directly attributable to the issue of new shares or options are shown in equity as a deduction, net of tax, from the
proceeds.
(v) Dividends
Provision is made for the amount of any dividend declared, being appropriately authorised and no longer at the discretion of the entity, on
or before the end of the reporting period but not distributed at the end of the reporting period.
(w) Earnings Per Share
(i) Basic Earnings Per Share
Basic earnings per share is calculated by dividing the profit attributable to owners of the Company, excluding any costs of servicing equity
other than ordinary shares, by the weighted average number of ordinary shares outstanding during the financial year.
(ii) Diluted Earnings Per Share
Diluted earnings per share adjusts the figures used in the determination of basic earnings per share to take into account the after income
tax effect of interest and other financing costs associated with dilutive potential ordinary shares and the weighted average number of
additional ordinary shares that would have been outstanding assuming the exercise of all dilutive potential ordinary shares.
(x) Goods and Services Tax (GST)
Revenues, expenses and assets are recognised net of the amount of GST, unless the GST incurred is not recoverable from the taxation
authority. In this case it is recognised as part of the cost of acquisition of the asset or as part of the expense.
Receivables and payables are stated inclusive of the amount of GST receivable or payable. The net amount of GST recoverable from, or
payable to, the taxation authority is included with other receivables or payables in the balance sheet.
Cash flows are presented on a gross basis. The GST components of cash flows arising from investing or financing activities which are
recoverable from, or payable to the taxation authority, are presented as operating cash flows.
58
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(y) Parent Entity Financial Information
The financial information for the Parent Entity, Central Petroleum Limited, disclosed in Note 25, has been prepared on the same basis as
the consolidated financial statements except for investments in subsidiaries, associates and joint venture entities which are accounted for
at cost in the financial statements of Central Petroleum Limited.
(z) Business Combinations
The acquisition method of accounting is used to account for all business combinations, regardless of whether equity instruments or other
assets are acquired. The consideration transferred for the acquisition of a subsidiary comprises the:
•
•
•
•
•
fair values of the assets transferred;
liabilities incurred to the former owners of the acquired business;
equity interests issued by the Group;
fair value of any asset or liability resulting from a contingent consideration arrangement; and
fair value of any pre-existing equity interest in the subsidiary.
Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are, with limited exceptions,
measured initially at their fair values at the acquisition date. The Group recognises any non-controlling interest in the acquired entity on an
acquisition-by-acquisition basis either at fair value or at the non-controlling interest’s proportionate share of the acquired entity’s net
identifiable assets.
Acquisition related costs are expensed as incurred.
The excess of the:
consideration transferred;
•
• amount of any non-controlling interest in the acquired entity; and
• acquisition-date fair value of any previous equity interest in the acquired entity.
over the fair value of the net identifiable assets acquired is recorded as goodwill. If those amounts are less than the fair value of the net
identifiable assets of the business acquired, the difference is recognised directly in profit or loss as a bargain purchase.
Where settlement of any part of cash consideration is deferred, the amounts payable in the future are discounted to their present value as
at the date of exchange. The discount rate used is the entity’s incremental borrowing rate, being the rate at which a similar borrowing
could be obtained from an independent financier under comparable terms and conditions.
Contingent consideration is classified either as equity or a financial liability. Amounts classified as a financial liability are subsequently
remeasured to fair value with changes in fair value recognised in profit or loss.
If the business combination is achieved in stages, the acquisition date carrying value of the acquirer’s previously held equity interest in the
acquiree is remeasured to fair value at the acquisition date. Any gains or losses arising from such remeasurement are recognised in profit
or loss.
(aa) Standards, Amendments and Interpretations
(i) New and Amended Standards Adopted by the Group
In the current period, the Group has adopted all new and revised Standards and Interpretations issued by the Australian Accounting
Standards Board that are relevant to its operations and effective for reporting periods beginning on or after 1 July 2019.
(a) AASB 16 Leases
The Group has adopted AASB 16 Leases using the modified retrospective approach from 1 July 2019, and as a result has not restated
comparatives for the 2019 reporting period as permitted under the specific transitional provisions in the standard. The reclassifications and
adjustments arising from the new leasing rules are therefore recognised in the opening balance sheet on 1 July 2019.
The description of the Group’s leasing activities and how they are accounted for is contained in Note 11(c).
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
59
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(aa) Standards, Amendments and Interpretations (continued)
(i) New and Amended Standards Adopted by the Group (continued)
The impact of adopting AASB 16 Leases on the Group’s financial statements
On adoption of AASB 16, the Group recognised lease liabilities in relation to leases which had previously been classified as ‘operating
leases’ under the principles of AASB117 Leases. These liabilities were measured at the present value of the remaining lease payments,
discounted using the lessee’s incremental borrowing rate as of 1 July 2019. The weighted average lessee’s incremental borrowing rate
applied to the lease liabilities on 1 July 2019 was 7.3%. In determining the incremental borrowing rate, the Group was required to make
judgements around economic assumptions and specific risks associated with the underlying right-of-use asset.
In applying AASB 16 for the first time, the Group has used the following practical expedients permitted by the standard:
•
•
•
•
•
the use of a single discount rate to a portfolio of leases with reasonably similar characteristics;
reliance on previous assessments on whether leases are onerous;
the accounting for operating leases with a remaining lease term of less than 12 months as at 1 July 2019 as short-term leases
the exclusion of initial direct costs for the measurement of the right-of-use asset at the date of initial application; and
the use of hindsight in determining the lease term where the contract contains options to extend or terminate the lease.
The Group has also elected not to reassess whether a contract is or contains a lease at the date of initial application. Instead, for contracts
entered into before the transition date the Group relied on its assessment made applying AASB 117 and Interpretation 4 Determining
whether an Arrangement contains a Lease.
Measurement of lease liabilities
The lease liability recognised at 1 July 2019 is shown below:
Operating lease commitments disclosed as at 30 June 2019
(Less): short-term leases recognised on a straight-line basis as expense
Gross lease liabilities at 1 July 2019
Effect of discounting
Lease liability recognised as at 1 July 2019
Comprising:
Current lease liabilities
Non-current lease liabilities
Measurement of right-of-use assets
$’000
1,898
(30)
1,868
(253)
1,615
532
1,083
1,615
The associated right-of-use assets for property leases were measured on a retrospective basis as if the new rules had always been applied.
Other right-of use assets were measured at the amount equal to the lease liability, adjusted by the amount of any prepaid or accrued lease
payments relating to that lease recognised in the balance sheet as at 30 June 2019. There were no onerous lease contracts that would have
required an adjustment to the right-of-use assets at the date of initial application. The recognised right-of-use assets relate to the following
types of assets:
Land and buildings
Plant and equipment
Total right-of-use assets
60
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
1 July 2019
$’000
1,030
362
1,392
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(aa) Standards, Amendments and Interpretations (continued)
(i) New and Amended Standards Adopted by the Group (continued)
Adjustments recognised in the balance sheet on 1 July 2019
The change in accounting policy affected the following items in the balance sheet on 1 July 2019:
•
•
•
right-of-use assets increased by $1,392,000;
lease liabilities increased by $1,615,000; and
other financial liabilities decreased by $84,000.
The net impact on accumulated losses on 1 July 2019 was an increase of $140,000.
Impact on segment disclosures and earnings per share
EBITDA, segment assets and segment liabilities for June 2020 all increased as a result of the change in accounting policy. Lease liabilities are
now included in segment liabilities, whereas finance leases, if any, were previously excluded from segment liabilities. The following
segments were affected by the change in policy:
Producing Assets
Unallocated items
EBITDA1
$’000
82
568
650
Segment
Assets
$’000
Segment
Liabilities
$’000
334
725
1,059
344
882
1,226
1 EBITDA is Earnings before Interest, Taxation, Depreciation and Amortisation expense.
There was no impact on reported earnings per share.
2. REVENUE FROM CONTRACTS WITH CUSTOMERS
(a) Revenue from contracts with customers
Sale of hydrocarbon products - point in time
Natural gas
Crude oil and condensate
Total revenue from contracts with customers
2020
$’000
58,960
6,086
65,046
2019
$’000
49,658
9,700
59,358
Revenue relating to contracts with major customers is disclosed in Note 24 – Segment Reporting.
(b) Contract Liabilities
Deferred Revenue – take-or-pay contracts1
Deferred Revenue – other gas sales contracts2
2020
Non-
current
$’000
Total
$’000
Current
$’000
2019
Non-
current
$’000
Total
$’000
18,977
21,691
3,987
12,164
2,715
4,038
15,559
18,274
—
4,038
Current
$’000
2,714
8,177
Total contract liabilities
10,891
22,964
33,855
6,753
15,559
22,312
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
61
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
2. REVENUE FROM CONTRACTS WITH CUSTOMERS (CONTINUED)
(b) Contract Liabilities (continued)
Movements in contract liabilities
Carrying amount at 1 July 2019
Revenue recognised from the delivery of gas3
Gas paid for but not taken during the year
Amounts transferred from Other Financial Liabilities4
Total contract liabilities
Deferred
Revenue from
Take-or-Pay
Contracts
$’000
Deferred
Revenue from
Other
Contracts
$’000
18,274
—
3,417
—
21,691
4,038
(7,693)
—
15,819
12,164
Total
$’000
22,312
(7,693)
3,417
15,819
33,855
1 Take-or-pay proceeds received are taken to revenue at the earlier of physical delivery of the gas to the customer, or upon forfeiture of the right to gas under the
contract. No revenue has been recognised during the year for gas forfeited under take-or-pay contracts.
2 Deferred Revenue from other contracts represents gas pre-sold to customers which is yet to be delivered. Amounts are recognised as Deferred Revenue when no
cash settlement option exists for the customer. Where a cash settlement option previously existed, the amount transferred to Deferred Revenue is the equivalent
fair value of that cash settlement option at the time that option ceased to be available.
3 There were no cash inflows during the period associated with the delivery of this gas as the Group received up-front payment for the gas in 2016.
4 In July 2019, Macquarie Bank Limited novated its rights and obligations under the Second and Third Contract Years of the MBL Gas Sale and Prepayment
Agreement, to another party who will take physical delivery of the gas. As there is no cash settlement option under the novation agreement, there is no longer a
financial liability, and as a result, $15,819,000 previously recognised as Other Financial Liabilities has been transferred to Deferred Revenue. Classification of
current and non-current Deferred Revenue is based on the contractual rights of the customer to take gas in each contract year. Revenue is recognised as gas is
delivered under the new Gas Sale Agreement.
3. OTHER INCOME
Interest
Profit on disposal of exploration permits (a)
Profit on disposal of inventory and other assets
Other income
Total other income
2020
$’000
152
8,393
60
5
8,610
2019
$’000
360
—
—
25
385
(a)
In January 2020 the Consolidated Entity received a Sole Funding Commitment Termination Fee of $7,713,000 (2019: Nil) from its joint venture partner
in ATP 2031. Under the terms of the Joint Venture Agreement this amount represented the balance of consideration payable in respect of the transfer
of a 50% interest in the Permit to the joint venture partner.
The balance of $680,000 (2019: Nil) relates to the profit recorded on disposal of interests in Northern Territory exploration permits EP93, EP97 and
EP107 following government approval and registration of the transfer.
62
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
4. EXPENSES
(a) Loss before income tax includes the following specific expenses
NOTE
2020
$’000
2019
$’000
Depreciation
Buildings
Producing assets
Plant and equipment
Leasehold improvements
Right of use assets
Total depreciation
Amortisation
Software
Rental expense relating to operating leases not recognised on the Balance
Sheet – Minimum lease payments
Impairment expense
Finance costs
Interest and fees on debt facilities
Interest on lease liabilities
Interest on other financial liabilities
Revaluation of financial liabilities
Amortisation of deferred finance costs
Accretion charge
Total finance costs
(b) Government Grants
10
10
10
10
11
13
11(b)
4(c)
11(b)
350
9,945
5,353
40
492
350
7,851
4,395
40
—
16,180
12,636
77
39
177
5,191
102
56
(2)
575
511
6,433
59
736
—
6,466
—
650
(164)
1,133
490
8,575
In response to the impacts of COVID-19 the Australian Government has made the JobKeeper support package to eligible affected
businesses. The Company recognised subsidies totalling $759,000 (2019: Nil) against employee costs.
(c)
Impairment of Exploration Assets
The Consolidated Entity fully impaired the assets relating to exploration tenement EP105 and application area EP(A)130 amounting to
$177,000 (2019: Nil). The impairment was based on the limited likelihood of future work being undertaken in those areas.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
63
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
5.
INCOME TAX
This note provides an analysis of the Group’s income tax expense, shows what amounts are recognised directly in equity and how the tax
credit is affected by non-assessable and non-deductible items. It also explains significant estimates made in relation to the Group’s tax
position.
2020
$’000
2019
$’000
(a)
Income tax expense
Current tax
Deferred tax
Income tax expense
(b) Numerical reconciliation of income tax expense
and prima facie tax benefit
Profit/(Loss) before income tax expense
Prima facie tax (expense)/benefit at 30% (2019: 30%)
Tax effect of amounts which are not deductible in calculating taxable income:
Non-deductible expenses
Share based payments
Other items
Sub-total
Deferred tax assets not recognised
Recognition of previously unrecognised deferred tax assets
Income tax expense
(c) Amounts recognised directly in equity
Aggregate deferred tax arising in the reporting period and not recognised in net
profit or loss or other comprehensive income but directly debited or credited to
equity:
Net deferred tax – debited directly to equity
Deferred tax assets not recognised
Net amounts recognised directly in equity
(d) Tax Losses
—
—
—
5,411
(1,623)
(180)
(581)
(8)
(2,392)
—
2,392
—
45
(45)
—
—
—
—
(14,526)
4,358
(342)
(181)
(1)
3,834
(3,834)
—
—
—
—
—
Unutilised tax losses for which no deferred tax asset has been recognised
Potential tax benefit at 30%
126,635
37,991
127,225
38,167
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.
64
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
5.
INCOME TAX (CONTINUED)
(e) Deferred tax assets and liabilities
2020
$’000
2019
$’000
Deferred tax assets
Provisions and accruals
Financial liabilities
Deferred revenue
Other expenditure
Borrowing costs
Unutilised losses
Total deferred tax assets before set-offs
Set-off of deferred tax liabilities pursuant to set-off provisions
Net deferred tax assets not recognised
Movements in deferred tax assets
Opening balance at 1 July
(Charged) / Credited to the income statement
Closing balance at 30 June
Deferred tax assets to be recovered after more than 12-months
Deferred tax assets to be recovered within 12-months
Deferred tax liabilities
Accrued income
Capitalised exploration
Property, plant and equipment
Total deferred tax liabilities before set-offs
Set-off of deferred tax assets pursuant to set-off provisions
Net deferred tax liabilities
Movements in deferred tax liabilities
Opening balance at 1 July
(Credited) / Charged to the income statement
Closing balance at 30 June
Deferred tax liabilities to be recovered after more than 12-months
Deferred tax liabilities to be recovered within 12-months
14,171
—
1,845
425
56
52,267
68,764
(14,276)
54,488
14,454
(178)
14,276
11,299
2,977
14,276
3
2,503
11,770
14,276
(14,276)
—
14,454
(178)
14,276
14,097
179
14,276
14,644
2,384
610
569
38
52,621
70,866
(14,454)
56,412
13,916
538
14,454
11,556
2,898
14,454
11
476
13,967
14,454
(14,454)
—
13,916
538
14,454
14,443
11
14,454
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
65
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
6. REMUNERATION OF AUDITORS
The following fees were paid or payable for services provided by PwC Australia,
the auditor of the Company, its related practices and non-related audit firms:
(i) Audit and other assurance services
Audit and review of Group financial statements
Audit of separate subsidiary financial statements
(ii) Taxation services
Income Tax compliance
R&D Services
Other tax related services
(iii) Other services
Consulting services
2020
$
2019
$
198,578
—
198,578
14,657
—
26,092
40,749
—
—
219,920
43,430
263,350
8,670
35,350
44,752
88,772
8,865
8,865
Total remuneration of PwC
239,327
360,987
7. CASH AND CASH EQUIVALENTS
Cash at bank and in hand
Made up as follows:
Corporate (a)
Joint arrangements (b)
2020
$
25,918
25,252
666
25,918
2019
$
17,806
17,296
510
17,806
(a) $5,486,000 of this balance relates to cash held with Macquarie Bank Limited to be used for allowable purposes under the Facility
Agreement (2019: $3,085,000), including, but not limited to operating costs for the Palm Valley, Dingo and Mereenie fields, taxes, and
debt servicing.
(b) This balance relates to the Group’s share of cash balances held under Joint Venture Arrangements.
(i) Risk exposure
The Group’s exposure to interest rate risk is discussed in Note 33(c). The maximum exposure to credit risk at the end of the reporting
period is the carrying amount of cash and cash equivalents.
8. TRADE AND OTHER RECEIVABLES
Current
Trade receivables
Accrued income (a)
Other receivables
Prepayments
2020
$’000
476
4,698
279
1,321
6,774
2019
$’000
372
7,427
31
1,230
9,060
(a) Accrued income relates to the revenue recognition of hydrocarbon volumes delivered to respective customers but not yet invoiced.
Due to the nature of the Group’s receivables, their carrying values are considered to approximate their fair values. The Group applies the
simplified approach to providing for expected credit losses (refer Note 33(a)).
66
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
9.
INVENTORIES
Crude oil and natural gas
Spare parts and consumables
Drilling materials and supplies at cost
2020
$’000
61
1,975
545
2,581
10. PROPERTY, PLANT AND EQUIPMENT
Freehold Land
and Buildings
$’000
Producing
Assets
$’000
Plant and
Equipment
$’000
Year ended 30 June 2019
Opening net book amount
Additions
Changes to rehabilitation estimates
Disposals and write offs
Depreciation charge
Closing net book amount
At 30 June 2019
Cost
Accumulated depreciation
Net book amount
Year ended 30 June 2020
Opening net book amount
Additions
Changes to rehabilitation estimates
Disposals and write offs
Depreciation charge
Closing net book amount
At 30 June 2020
Cost
Accumulated depreciation
Net book amount
11. LEASES
2,879
—
—
—
(350)
2,529
3,869
(1,340)
2,529
2,529
—
—
—
(350)
2,179
3,869
(1,690)
2,179
72,831
—
16,066
—
(7,851)
81,046
28,143
16,188
6
(2)
(4,435)
39,900
100,889
(19,843)
65,546
(25,646)
81,046
39,900
123,475
81,046
264
(2,769)
—
(9,945)
68,596
98,384
(29,788)
68,596
39,900
2,593
(5)
(25)
(5,393)
37,070
123,475
2,857
(2,774)
(25)
(15,688)
107,845
67,800
(30,730)
170,053
(62,208)
37,070
107,845
(a) Amounts recognised in the balance sheet
The balance sheet shows the following amounts relating to leases:
Right-of-use assets
Land & Buildings
Plant & Equipment
Lease Liabilities
Current
Non-current
2020
$’000
673
386
1,059
608
618
1,226
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
2019
$’000
108
1,870
742
2,720
Total
$’000
103,853
16,188
16,072
(2)
(12,636)
123,475
170,304
(46,829)
2019
$’000
—
—
—
—
—
—
67
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
11. LEASES (CONTINUED)
(a) Amounts recognised in the balance sheet (continued)
In the previous year, the Group only recognised lease assets and lease liabilities in relation to leases that were classified as ‘finance leases’
under AASB 117 Leases. Refer to Note 1(aa) for more information on the impact of the change in accounting policy.
Additions to the right-of-use assets during the 2020 financial year were $159,000.
(b) Amounts recognised in the statement of profit or loss
The statement of profit or loss shows the following amounts relating to leases:
Depreciation charge of right-of-use assets
Land & Buildings
Plant & Equipment
Total depreciation of right-of-use assets
Interest expense
Expense related to short term leases included in cost of sales and general and
administrative expenses
The total cash outflow for leases in 2020 was $650,000.
2020
$’000
2019
$’000
359
133
492
102
39
—
—
—
—
—
(c) The Group’s leasing activities and how they are accounted for
The Group leases office space, property easements, equipment and vehicles. Rental contracts are typically made for fixed periods of 3 to 8
years but may have extension options as described below. Lease terms are negotiated on an individual basis and contain a wide range of
different terms and conditions. The lease agreements do not impose any covenants, but 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.
Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. The lease agreements do not
impose any covenants other than the security interests in the leased assets that are held by the lessor. Leased assets may not be used as
security for borrowing purposes.
Until the 2019 financial year, all of the Group’s leases of property, plant and equipment were classified as operating leases. Payments made
under operating leases (net of any incentives received from the lessor) were charged to profit or loss on a straight-line basis over the
period of the lease. From 1 July 2019, 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.
68
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
11. LEASES (CONTINUED)
(c) The Group’s leasing activities and how they are accounted for (continued)
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.
12. EXPLORATION ASSETS
Acquisition costs of right to explore
Movement for the year:
Balance at the beginning of the year
Impairment expense (Note 4(c))
Balance at the end of the year
2020
$’000
8,722
8,899
(177)
8,722
2019
$’000
8,899
8,899
—
8,899
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 69
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
13.
INTANGIBLE ASSETS
Software
At the beginning of the year
Cost
Accumulated amortisation
Net book value
Movements for the year
Opening net book amount
Additions
Amortisation
Closing net book amount
At the end of the year
Cost
Accumulated amortisation
Net book value
2020
$’000
2019
$’000
512
(399)
113
113
276
(77)
312
788
(476)
312
495
(339)
156
156
16
(59)
113
512
(399)
113
14. OTHER FINANCIAL ASSETS
Non-Current
Security bonds on exploration permits and rental properties
2,656
2,771
Security bonds are provided to State or Territory governments in respect of certain performance obligations arising from awarded
petroleum and mineral tenements. The bonds are typically provided as cash or as bank guarantees in favour of the State or Territory
government secured by term deposits with the financial institution providing the bank guarantee.
15. GOODWILL
Goodwill arising from business combinations
Impairment tests for goodwill
2020
$’000
3,906
2019
$’000
3,906
Goodwill is monitored by management at the level of the operating segments and has been allocated to the gas producing assets cash
generating unit. There has been no impairment of amounts previously recognised as goodwill. Goodwill is tested for impairment where an
indicator of impairment exists, and at least on an annual basis.
In determining impairment indicators, an assessment of the fair value less cost of disposal is made by estimating future cash flows from
available 2P reserves over a 20-year period from balance date, being the period over which the value of existing reserves is expected to be
substantially realised. Cash flows include estimated capital expenditure to enhance production. The future cash flows are discounted to
their present value using a post-tax discount rate, which includes an assessment of asset specific risks and the time value of money. The
calculations require significant management judgement and are subject to risk and uncertainty, and broader economic conditions.
The impacts of COVID-19 are forecast to continue to affect short term demand and this has been factored into estimated future cash flows.
The following table sets out the key assumptions used in assessing the fair value less cost to sell of producing assets:
2020
Producing Assets
Sales volumes
Sales price (% annual growth rate)
Operating costs (% annual growth rate)
Post-tax discount rate (%)
2P Reserves
2 - 2.5%
2 - 2.5%
11.00%
70
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
15. GOODWILL (CONTINUED)
Management has determined the values assigned to each of the above key assumptions as follows:
Assumption
Approach used to determine values
Sales volume
Sales price
Natural gas sales are based on both Annual Contract Quantities for existing contracts which continue at
projected nominations and uncontracted volumes taking into account firm plant capacity, and subject to
2P reserves. Crude and condensate volumes are based on projected field production, taking into account
historical production and forecast reservoir decline.
Existing contracts are based on current contracted prices escalated for CPI increases as per the contract
terms. Some contracts contain minimum and maximum increases. Uncontracted gas sales are based on
estimated attainable gas prices taking into account indicative customer proposals. Crude and condensate
pricing is based on a mid-point of independent analyst forecasts of crude prices and a long-term forecast
average USD exchange rate. The Group’ s oil and gas price forecasts take into account any expected impact
of climate change, potential policy responses and other factors that may impact longer term forecasts.
Operating costs
Current budgeted operating costs which are based on past performance and expectations for the future.
Forecasts are inflated beyond the budget year using inflationary estimates. Other known factors are
included where applicable and known with certainty.
Capital expenditure
Expected cash costs where further field capital expenditure is required in order to meet contracted and
projected sales volumes.
Annual growth rate
This is the average growth rate used to extrapolate cash flows beyond the budget period. Management
considers forecast inflation rates and industry trends if applicable.
Post-tax discount rate
This rate reflects risks relating to the segment. Post-tax discount rates have been applied to discount the
forecast future post-tax cash flows.
16. TRADE AND OTHER PAYABLES
Current
Trade payables
Other payables
Tax related payables
Deposits held
Accruals
2020
$’000
2,026
11
—
—
3,250
5,287
2019
$’000
2,079
40
634
150
3,103
6,006
Trade payables are usually non-interest bearing provided payment is made within the terms of credit. The Consolidated Entity’s exposure
to liquidity and currency risks related to trade and other payables is disclosed in Note 33.
17. BORROWINGS
(a)
Current1
Debt facilities
(b)
Non-current1
Debt facilities
1 Details regarding interest bearing liabilities are contained in Note 33(e).
2020
$’000
6,964
6,964
63,809
63,809
2019
$’000
10,957
10,957
70,773
70,773
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
71
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
18. OTHER FINANCIAL LIABILITIES
Current
Lease incentive liabilities
Liabilities associated with forward gas sales agreements containing a cash
settlement option (a)
Non-Current
Lease incentive liabilities
Liabilities associated with forward gas sales agreements containing a cash
settlement option (a)
2020
$’000
—
—
—
—
—
—
2019
$’000
39
1,986
2,025
45
13,779
13,824
(a) The balance at 30 June 2019 represents the remaining liabilities under the Second and Third Contract Year of the MBL Gas Sale and
Prepayment Agreement where Macquarie Bank Limited had an option to receive a financial settlement in lieu of physical gas delivery.
In July 2019 Macquarie Bank Limited novated its rights and obligations under those remaining contract years to a third party. This
resulted in an amount of $15,819,000 being reclassified from Other Financial Liabilities to Deferred Revenue (Note 2(b)).
19. PROVISIONS
Employee entitlements (a)
Restoration and rehabilitation (b)
Other:
Joint Venture production over-lift (c)
Other provisions (d)
2020
Current Non-Current
$’000
$’000
3,942
120
712
—
828
37,988
3,460
—
Total
$’000
4,770
38,108
4,172
—
4,774
42,276
47,050
2019
Current Non-Current
$’000
$’000
763
38,323
4,008
—
3,530
529
—
1,317
5,376
Total
$’000
4,293
38,852
4,008
1,317
43,094
48,470
(a) The current provision for employee entitlements includes accrued short term incentive plans, severance entitlements, accrued annual
leave and the unconditional entitlements to long service leave where employees have completed the required period of service. The
amounts are presented as current, since the Consolidated Entity does not have an unconditional right to defer settlement for these
obligations. However, based on past experience, the Group does not expect all employees to take the full amount of accrued leave or
require payment in the next 12-months. Current leave obligations that are not expected to be taken or paid within the next
12-months amount to $788,000 (2019: $739,000).
(b) Provisions for future removal and restoration costs are recognised where there is a present obligation and it is probable that an
outflow of economic benefits will be required to settle the obligation. The estimated future obligations include the costs of removing
facilities, abandoning wells and restoring the affected areas.
(c) Under an Interim Gas Balancing Agreement with its joint venture partners, the Group has taken a higher proportion of natural gas
produced from the Mereenie joint venture than its joint venture percentage entitlement. A provision has been recognised to reflect
the expected additional production costs of rebalancing production entitlements between the joint venture partners from future
operations.
(d) Other Provisions comprises provisions for liquidated damages under gas sales agreements and settlement of legal matters (both nil at
30 June 2020).
72
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
19. PROVISIONS (CONTINUED)
Movements in Provisions
Movements in each class of provision during the financial year are set out below:
2020
Carrying amount at start of year
Change in provision charged to property, plant
and equipment
Additional provisions charged to profit or loss
Unwinding of discount
Amounts used during the year
Carrying amount at end of year
20. CONTRIBUTED EQUITY
(a) Share capital
Employee
Entitlements
$’000
Restoration &
Rehabilitation
$’000
Joint Venture
Production
Over-Lift
$’000
Other
$’000
Total
$’000
4,293
38,852
4,008
1,317
48,470
—
2,975
—
(2,498)
4,770
(2,774)
1,527
511
(8)
38,108
—
733
—
(569)
—
22
—
(1,339)
(2,774)
5,257
511
(4,414)
4,172
—
47,050
2020
$’000
2019
$’000
723,288,869 fully paid ordinary shares (2019: 713,355,716)
197,776
197,776
Ordinary shares have no par value and the Company does not have a limited amount of authorised capital.
On a show of hands, every holder of ordinary shares present at a meeting in person or by proxy, is entitled to one vote, and upon a poll
each share is entitled to one vote.
Movements in ordinary share capital
2020
Number of Shares
2019
Number of Shares
Balance at start of year
Shares issued under Employee Incentive Plans
713,355,716
9,933,153
707,115,793
6,239,923
Balance at end of year
723,288,869
713,355,716
2020
$’000
197,776
—
197,776
2019
$’000
197,776
—
197,776
(b) Share Options
The following table shows the movement in options over ordinary shares during the year:
Class
Expiry Date
Exercise
Price
Balance at
Start of Year
Issued
During the
Year
Lapsed
During the
Year
Exercised
During the
Year
Balance at
the End of
the Year
Executive Share Option Plan
Unlisted financing options
Unlisted financing options
30 Jun 2023
01 Sep 2019
31 Dec 2019
$0.200
$0.194
$0.140
—
30,000,000
22,500,000
18,151,116
—
—
—
(30,000,000)
(22,500,000)
Total
52,500,000
18,151,116
(52,500,000)
—
—
—
—
18,151,116
—
—
18,151,116
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
73
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
20. CONTRIBUTED EQUITY (CONTINUED)
(c) Share rights under the Long Term Incentive Plan
Under the Group’s Employee Rights Plan, eligible employees may receive rights to shares in Central Petroleum Limited. The rights are
granted in respect of a plan year which commences 1 July each year. The share rights remain unvested until the end of the performance
period, which is three years commencing from the start of each plan year. Except in a limited number of circumstances, eligible employees
must still be in the employment of Central Petroleum Limited as at the vesting date for the rights to vest.
Final vesting percentages are determined by performance hurdles in respect of a combination of absolute total shareholder return and
relative total shareholder return compared to a specific group of exploration and production companies.
The number of rights to be granted to eligible employees is determined based on the maximum long term incentive amount applicable for
each eligible employee, being either a fixed dollar amount or a percentage of the employee’s base salary, divided by the volume weighted
average share price at the start of the plan year. The table below sets out the maximum number of share rights subject to performance
hurdles outstanding at year end and movements for the year.
Class
Expiry Date
Plan Year
Commencing
Balance at
Start of Year
Issued
During the
Year
Cancelled
or Lapsed
During the
Year
Exercised
During the
Year
Balance at
the End of
the Year
Employee LTIP rights
05 Jan 2021
1 Jul 2015
7,305
—
—
—
7,305
Employee LTIP rights
08 Dec 2022
1 Jul 2016
9,577,506
618,276
(3,080,300)
(6,536,096)
579,386
Employee LTIP rights
09 Feb 2022
1 Jul 2016
Employee LTIP rights
03 Oct 2022
1 Jul 2016
25,324
70,000
Employee LTIP rights
03 Oct 2022
1 Jul 2017
5,431,222
Employee LTIP rights
23 May 2023
1 Jul 2017
16,868
Employee LTIP rights
28 Jun 2023
1 Jul 2017
135,920
Employee LTIP rights
22 May 2024
1 Jul 2018
7,000,371
2,428
6,713
—
—
—
—
Employee LTIP rights
12 Nov 2024
1 Jul 2018
Employee LTIP rights
Employee STIP rights
30 Jun 2024
1 Jul 2019
13 Sep 2024
1 Jul 2018
—
—
—
1,837,109
7,804,260
3,311,771
—
(19,179)
(829,577)
—
—
(555,973)
—
(451,085)
(27,752)
(57,534)
—
—
—
—
—
—
—
4,601,645
16,868
135,920
6,444,398
1,837,109
7,353,175
—
(3,311,771)
—
Total
22,264,516
13,580,557
(4,936,114)
(9,933,153)
20,975,806
The rights do not entitle the holders to participate in any share issue of the Company or any other entity.
(d) Capital risk management
The Group’s objective when managing capital is to safeguard the ability to continue as a going concern to ultimately add value for
shareholders through the exploitation and production of hydrocarbon resources. This is monitored through the use of cash flow forecasts.
In order to maintain the capital structure, the Group may issue new shares or other equity instruments.
On 27 September 2018, the Company executed a $10 million Equity Line of Credit (ELOC) facility with Long State Investment Limited (LSI).
Under the terms of the facility, the Company may, at its discretion, issue shares to LSI at any time over 24 months from execution, up to a
total of $10 million. The Company may draw down up to $250,000 in any period of 5 trading days.
Any shares issued to LSI will be priced at the lowest daily weighted average price (VWAP) of the Company shares traded on each of the
5-trading days which follow an advance notice by the Company. A commission of 5% will be payable by the Company at the time of issue.
LSI may receive up to five million unlisted options through four separate tranches, subject to ELOC utilisation. An initial tranche of
1.25 million options with an exercise price of 35 cents will be granted on activation of the ELOC. Further tranches of 1.25 million options,
with an exercise price of 200% of the 20-day VWAP immediately preceding the date on which the Company is required to grant the
options, will be granted when the aggregate advances first exceeds $2.5 million, $5 million, and $7.5 million. The options have an exercise
period of five years from the date of issue.
To date, the Company has not utilised the ELOC facility and no options have been granted to LSI. The facility expires 27 September 2020.
74
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
21. RESERVES
Share options reserve
Movements:
Balance at start of year
Share based payment costs (a)
Options issued for financing
Transaction costs
Balance at end of year
2020
$’000
27,238
25,310
1,937
—
(9)
27,238
2019
$’000
25,310
23,464
602
1,244
—
25,310
(a)
Share based payments are provided to employees under the Employee Rights Plan and Executive Share Option Plan. Refer to
Note 32 for further details of share-based payments.
22. ACCUMULATED LOSSES
Movements in accumulated losses were as follows:
Balance at the start of year (a)
Net profit/(loss) for the year
Balance at end of year
2020
$’000
(228,843)
5,411
(223,432)
(a)
2020 restated for change in accounting policy. Refer to Statement of Changes in Equity and Note 1(aa).
23. EARNINGS/(LOSS) PER SHARE
(a)
Basic earnings/(loss) per share (cents)
(b)
Diluted earnings/(loss) per share (cents)
2020
0.75
0.75
2019
$’000
(214,177)
(14,526)
(228,703)
2019
(2.05)
(2.05)
(c)
Profit/(loss) used in earnings/(loss) per share calculation
Profit/(loss) attributed to ordinary equity holders ($’000)
5,411
(14,526)
(d) Weighted average number of ordinary shares
Weighted average number of shares used as the denominator in
calculating basic earnings/(loss) per share
Adjustments for the calculation of diluted earnings per share:
720,898,329
709,669,029
Employee share rights
1,057,114
—
Weighted average number of shares used as the denominator in
calculating diluted earnings/(loss) per share
721,955,443
709,669,029
Options and Rights on issue are considered to be potential ordinary shares and have not been included in the calculation of basic earnings
per share. Additionally, in the prior year, any exercise of the options 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 in 2019.
24. SEGMENT REPORTING
The Group has identified its operating segments based on the internal reports that are reviewed and used by the Executive Management
Team (the chief operating decision makers) in assessing performance and in determining the allocation of resources. The following
operating segments are identified by management based on the nature of the business or venture.
(a) Producing assets
Production and sale of crude oil, natural gas and associated petroleum products from fields that are in the production phase.
(b) Development assets
Fields under development in preparation for the sale of petroleum products. There were no fields under development during the current
or prior financial year.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
75
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
24. SEGMENT REPORTING (CONTINUED)
(c) Exploration assets
Exploration and evaluation of permit areas.
(d) Unallocated items
Unallocated items comprise non-segmental items of revenue and expenses and associated assets and liabilities not allocated to operating
segments as they are not considered part of the core operations of any segment.
(e) Performance monitoring and evaluation
Management monitors the operating results of the operating segments separately for the purpose of making decisions about resource
allocation and performance assessment.
The Consolidated Entity’s operations are wholly in one geographical location, being Australia.
2020
Revenue from contracts with customers
Natural gas
Crude oil and condensate
Total revenue from contracts with customers
Cost of sales
Gross profit
Other income
Share based employee benefits1
General and administrative expenses
Employee benefits and associated costs
EBITDAX2
Depreciation and amortisation1
Exploration expenditure
Interest revenue
Finance costs
Impairment expense1
Profit / (loss) before income tax
Taxes
Profit / (loss) for the year
Segment assets
Segment liabilities
Capital expenditure
Property, plant and equipment
Intangibles
Total capital expenditure
Producing
Assets
2020
$’000
Exploration
Assets
2020
$’000
Unallocated
Items
2020
$’000
Consolidation
2020
$’000
58,960
6,086
65,046
(33,386)
31,660
9
—
—
—
31,669
(15,528)
(678)
47
(5,860)
—
9,650
—
9,650
—
—
—
—
—
8,437
—
—
—
8,437
—
(4,599)
–
(18)
(177)
3,643
—
3,643
—
—
—
—
—
12
(1,937)
(266)
(4,512)
(6,703)
(729)
—
105
(555)
—
(7,882)
—
(7,882)
58,960
6,086
65,046
(33,386)
31,660
8,458
(1,937)
(266)
(4,512)
33,403
(16,257)
(5,277)
152
(6,433)
(177)
5,411
—
5,411
132,817
10,958
15,998
159,773
(141,530)
(3,301)
(13,360)
(158,191)
2,763
23
2,786
—
—
—
94
253
347
2,857
276
3,133
1 Non-cash item.
2 EBITDAX is earnings before interest, taxation, depreciation, amortisation, and exploration expense.
76
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
24. SEGMENT REPORTING (CONTINUED)
(e) Performance monitoring and evaluation (continued)
2019
Revenue from contracts with customers
Natural gas
Crude oil and condensate
Total revenue from contracts with customers
Cost of sales
Gross profit
Other income
Share based employee benefits
General and administrative expenses
Employee benefits and associated costs
EBITDAX
Depreciation and amortisation
Exploration expenditure
Interest revenue
Finance costs
Loss before income tax
Taxes
Loss for the year
Segment assets
Producing
Assets
2019
$’000
Exploration
Assets
2019
$’000
Unallocated
Items
2019
$’000
Consolidation
2019
$’000
49,658
9,700
59,358
(30,369)
28,989
19
—
—
—
29,008
(12,378)
(14,803)
103
(7,932)
(6,002)
—
(6,002)
—
—
—
—
—
—
—
—
—
—
—
(999)
1
(40)
(1,038)
—
(1,038)
—
—
—
—
—
6
(602)
(1,032)
(5,194)
(6,822)
(317)
—
256
(603)
(7,486)
—
(7,486)
49,658
9,700
59,358
(30,369)
28,989
25
(602)
(1,032)
(5,194)
22,186
(12,695)
(15,802)
360
(8,575)
(14,526)
—
(14,526)
143,023
11,068
14,659
168,750
Segment liabilities
(158,285)
(2,991)
(13,091)
(174,367)
Capital expenditure
Property, plant and equipment
Intangibles
16,078
—
16,078
—
—
—
Revenue from external customers by geographical location of production:
Australia
Non-current assets by geographical location:
Australia
110
17
127
2020
$’000
16,188
17
16,205
2019
$’000
65,046
59,358
124,500
139,164
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
77
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
24. SEGMENT REPORTING (CONTINUED)
(f) Major Customers
Customers with revenue exceeding 10% of the Group’s total hydrocarbon sales revenue are shown below. Revenues from these customers
are reported in the Producing Assets segment.
Largest customer
Second largest customer
Third largest customer
Fourth largest customer
Fifth largest customer
2020
$’000
18,918
12,712
9,629
8,504
7,649
% of Sales
Revenue
29%
20%
15%
13%
12%
2019
$’000
22,706
8,830
7,154
6,363
5,695
% of Sales
Revenue
38%
15%
12%
11%
10%
25. PARENT ENTITY INFORMATION
(a) Summary financial information
The individual financial summary statements for the Parent Entity show the following aggregate amounts:
Balance Sheet
Current assets
Non-current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Net assets
Shareholders’ equity
Issued capital
Reserves
Accumulated losses
Total equity
Profit/(Loss) for the year
Total comprehensive profit/(loss)
2020
$’000
21,983
23,797
45,780
(21,749)
(1,372)
(23,121)
22,659
197,776
27,238
(202,355)
22,659
10,829
10,829
2019
$’000
16,128
23,291
39,419
(28,344)
(1,032)
(29,376)
10,043
197,776
25,310
(213,043)
10,043
(13,128)
(13,128)
(b) Guarantees entered into by the Parent Entity
Guarantees have been provided by the Parent Entity to subsidiaries arising out of the course of ordinary operations.
A loan facility exists under which the parent 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 as available when no default exists. Revenues resulting from operations outside of these assets (such as the Surprise field) are
not subject to a cash sweep or other restrictions under the Facility where no defaults exist.
(c) Commitments of the Parent Entity
Operating lease commitments of the Parent Entity are set out in Note 31(c).
78
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
26. RELATED PARTY TRANSACTIONS
(a) Parent Entity
The parent entity is Central Petroleum Limited.
(b) Subsidiaries
The consolidated financial statements include the financial statements of Central Petroleum Limited and the subsidiaries listed in the
following table:
Name of Entity
Place of Incorporation
Class of Shares
Merlin Energy Pty Ltd
Central Petroleum Projects Pty Ltd
Helium Australia Pty Ltd
Ordiv Petroleum Pty Ltd
Frontier Oil & Gas Pty Ltd
Central Petroleum Eastern Pty Ltd
Central Geothermal Pty Ltd
Central Petroleum Services Pty Ltd
Central Petroleum PVD Pty Ltd
Central Petroleum (NT) Pty Ltd
Jarl Pty Ltd
Central Petroleum Mereenie Pty Ltd
Central Petroleum Mereenie Unit Trust
Central Petroleum WS (NO 1) Pty Ltd
Central Petroleum WS (NO 2) Pty Ltd
Western Australia
Western Australia
Victoria
Western Australia
Western Australia
Western Australia
Western Australia
Western Australia
Queensland
Queensland
Queensland
Queensland
N/A
Queensland
Queensland
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Units
Ordinary
Ordinary
(c) Key management personnel compensation
Short-term employee benefits
Post-employment benefits
Termination benefits
Long-term benefits
Share based payments
Detailed remuneration disclosures are provided in the remuneration report on pages 30 to 43.
Equity Holding
2020
%
2019
%
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
2020
$
3,040,943
166,369
—
40,105
846,280
2019
$
3,120,547
179,537
80,908
(81,319)
(21,388)
4,093,697
3,278,285
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
79
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
27. DEED OF CROSS GUARANTEE
Central Petroleum Limited and its wholly owned subsidiary companies are parties to a deed of cross guarantee under which each company
guarantees the debts of the others. By entering into the deed, the wholly-owned entities have been relieved from the requirement to
prepare a financial report and Directors’ Report under ASIC Corporations (Wholly-owned Companies) Instrument 2016/785.
The parties to the deed of cross guarantee are:
Central Petroleum Eastern Pty Ltd
Central Petroleum Limited
Central Petroleum Projects Pty Ltd
•
•
• Ordiv Petroleum Pty Ltd
•
•
•
•
•
Central Petroleum Services Pty Ltd
Central Petroleum (NT) Pty Ltd
Central Petroleum Mereenie Pty Ltd
Central Petroleum WS (NO 2) Pty Ltd
Helium Australia Pty Ltd
Frontier Oil & Gas Pty Ltd
Central Geothermal Pty Ltd
• Merlin Energy Pty Ltd
•
•
•
•
•
•
Central Petroleum PVD Pty Ltd
Jarl Pty Ltd
Central Petroleum WS (NO 1) Pty Ltd
(a) Consolidated statement of profit or loss, statement of comprehensive income and summary of
movements in consolidated retained earnings
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 2020.
2020
$’000
26,505
(11,389)
15,116
8,604
(1,937)
413
(8,441)
(4,512)
(5,234)
(4,367)
(177)
(535)
1,570
1,035
—
1,035
(214,888)
(139)
1,035
(213,992)
2019
$’000
18,046
(14,437)
3,609
354
(602)
(300)
(4,309)
(5,194)
(15,482)
(5,252)
—
(27,176)
6,540
(20,636)
—
(20,636)
(194,252)
—
(20,636)
(214,888)
Revenue from the sale of goods
Cost of sales
Gross profit
Other income
Share based employment benefits
General and administrative expenses
Depreciation and amortisation
Employee benefits and associated costs
Exploration expenditure
Finance costs
Impairment expense
Loss before income tax
Income tax credit
Profit/(Loss) for the year
Other comprehensive profit/(loss) for the year, net of tax
Total comprehensive profit/(loss) for the year
Accumulated losses at the beginning of the financial year
AASB 16 Lease accounting adjustments
Profit/(Loss) for the year
Accumulated losses at the end of the financial year
80
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
27. DEED OF CROSS GUARANTEE (CONTINUED)
(b) Consolidated balance sheet
Set out below is a consolidated balance sheet of the closed group as at 30 June.
ASSETS
Current assets
Cash and cash equivalents
Trade and other receivables
Inventories
Total current assets
Non-current assets
Property, plant and equipment
Right of use assets
Exploration assets
Intangible assets
Other financial assets
Deferred Tax Assets
Goodwill
Total non-current assets
Total assets
LIABILITIES
Current liabilities
Trade and other payables
Deferred revenue
Borrowings
Lease liabilities
Other financial liabilities
Provisions
Total current liabilities
Non-current liabilities
Deferred revenue
Borrowings
Lease liabilities
Other financial liabilities
Provisions
Total non-current liabilities
Total liabilities
Net assets
EQUITY
Contributed equity
Reserves
Accumulated losses
Total equity
2020
$’000
25,652
3,941
1,172
30,765
55,797
833
8,722
286
2,110
5,456
3,906
77,110
107,875
13,800
1,983
3,846
562
—
4,062
24,253
18,537
35,389
431
—
18,243
72,600
96,853
11,022
197,776
27,238
(213,992)
2019
$’000
17,296
3,398
1,394
22,088
65,997
—
8,899
73
2,255
5,636
3,906
86,766
108,854
13,699
1,983
6,675
—
39
4,380
26,776
15,119
39,224
—
45
19,491
73,879
100,655
8,199
197,776
25,310
(214,887)
11,022
8,199
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
81
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
28. RECONCILIATION OF PROFIT OR LOSS AFTER INCOME TAX TO NET
CASH FLOWS FROM OPERATING ACTIVITIES
Profit/(loss) after income tax
Adjustments for:
Depreciation and amortisation
Impairment expense
(Profit)/loss on disposal of assets
Profit on disposal of exploration permits
Share-based payments
Financing costs and interest (non-cash)
Changes in assets and liabilities relating to operating activities:
Decrease / (increase) in trade and other receivables
Decrease in inventories
Decrease in trade and other payables
(Decrease)/increase in deferred revenue
Decrease in financial liabilities
Increase in provisions
Net cash inflow from operations
29. CASH FLOW INFORMATION
(a)
Non-cash investing and financing activities
2020
$’000
5,411
16,257
177
(51)
(8,393)
1,937
834
2,290
138
(481)
(4,275)
—
1,883
15,727
2019
$’000
(14,526)
12,695
—
2
—
602
1,633
(2,429)
856
(829)
1,349
(39)
3,151
2,465
Non-cash interest relating to Other Financial Liabilities amounted to $56,000 (2019: $650,000). Additionally, non-cash revaluation credits
amounted to $2,000 (2019 credit of $164,000). Refer Note 4(a).
Due to a novation of rights and obligations under the MBL Gas Sale and Prepayment Agreement from MBL to a third party in respect of the
Second and Third Contract Years, an amount of $15,819,000 (2019: $Nil) was transferred to Deferred Revenue, reflecting the removal of
the cash settlement option (Refer Note 18 for further details).
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 32.
(b) Net debt reconciliation
This section provides an analysis of those liabilities for which cash flows have been or will be classified as financing activities in the
statement of cash flows. Cash balances included as current assets on the balance sheet are included as the Group considers these to form
part of its net debt.
Net debt
Cash and cash equivalents
Borrowings and leases – repayable within one year
Borrowings and leases – repayable after one year
Net debt
Cash
Gross Debt – fixed interest rates
Gross debt – variable interest rates
Net debt
82
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
2020
$’000
25,918
(7,572)
(64,427)
(46,081)
25,918
(1,226)
(70,773)
(46,081)
2019
$’000
17,806
(10,957)
(70,773)
(63,924)
17,806
—
(81,730)
(63,924)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
29. CASH FLOW INFORMATION (CONTINUED)
(b) Net debt reconciliation (continued)
Movement in Net Debt
Net debt 1 July 2018
Cash flows
Other non-cash movements
Net debt 30 June 2019
Other Assets
Liabilities from Financing Activities
Cash
$’000
27,223
(9,417)
—
17,806
Borrowings
$’000
Leases
$’000
(78,327)
(3,501)
98
(81,730)
—
—
—
—
Total
$’000
(51,104)
(12,918)
98
(63,924)
Recognised on adoption of AASB 16 (see Note 11)
—
—
(1,615)
(1,615)
17,806
8,112
—
—
25,918
(81,730)
(1,615)
(65,539)
11,501
—
(544)
548
(159)
—
20,161
(159)
(544)
(70,773)
(1,226)
(46,081)
Net debt 1 July 2019
Cash flows
Acquisition - leases
Other non-cash movements
Net debt 30 June 2020
30. CONTINGENCIES
(a) Contingent liabilities
(i)
Exploration Permits
The Consolidated Entity had contingent liabilities at 30 June 2020 in respect of certain joint arrangement payments. As partial
consideration under the terms of the purchase agreement for EP105 and EP106, there is a requirement to pay the vendor the sum
of $1,000,000 (2019: $1,000,000) within 12-months following the commencement of any future commercial production from the
permits. No commercial production is currently forecast from these permits.
(ii) Palm Valley Gas Field Gas Price Bonus
Under the Share Sale and Purchase Deed entered into with Magellan Petroleum Australia Pty Limited (Magellan) in February 2014
for the purchase of Palm Valley and Dingo gas fields and related assets, Central Petroleum Limited is obligated to pay to Magellan a
Gas Price Bonus where the weighted average price of gas sold from the Palm Valley gas field during a Contract Year exceeds certain
price hurdles during a period of 15-years following Completion of the Agreement.
The Gas Price Bonus Amount is calculated as 25% of the difference between the weighted average price of gas actually sold
(excluding GST and other costs) in a Contract Year and the gas price bonus hurdle applicable to that Contract Year (after adjusting
for CPI), multiplied by the actual volume of gas originating and sold from the Palm Valley gas field. The weighted average price of
gas sold from the Palm Valley gas field is currently below the Gas Price Bonus hurdle price and therefore no gas price bonus is
payable at this time. Based on current reserves and production profiles for the Palm Valley Gas Field, and current Northern
Territory gas market conditions, it is not anticipated that a gas price bonus will be payable over the relevant term and have
therefore ascribed a $nil value to this contingent liability. Should access to additional reserves and significantly higher priced
markets eventuate, this contingent liability will be reviewed. Importantly, any future payment of the Gas Price Bonus would only
occur where sales and revenues from the Palm Valley gas field materially exceed Central’s acquisition assumptions.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
83
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
31. COMMITMENTS
(a) Capital commitments
The Consolidated Entity has the following capital expenditure commitments:
The following amounts are due:
Within one year
(b) Exploration commitments
The Consolidated Entity has the following minimum exploration expenditure commitments:
The following amounts are due:
Within one year
Later than one year but not later than three years
Later than three years but not later than five years
Later than five years
2020
$’000
2019
$’000
475
475
609
609
10,578
55,087
8,100
—
73,765
12,175
46,105
4,450
6,000
68,730
These commitments may be varied in the future as a result of renegotiations of the terms of exploration permits. In the petroleum industry
it is common practice for entities to farm-out, transfer or sell a portion of their rights to third parties or relinquish (whole or part of the
permit) and, as a result, obligations may be reduced or extinguished.
(c) Operating lease commitments
The Consolidated Entity has non-cancellable operating leases. The leases have varying terms, escalation clauses and renewal rights. From
1 July 2019, the Group has applied AASB16 Leases, resulting in operating leases being recognised as right-of-use assets. The new policy is
set out in Note 11(c) and the impact of the change of accounting policy can be found in Note 1(aa).
Commitments for minimum lease payments in relation to non-cancellable operating leases not recognised as a lease liability on the balance
sheet are as follows:
Within one year
Later than one year but not later than five years
Later than five years
2020
$’000
10
—
—
10
2019
$’000
658
1,059
181
1,898
84
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
32. SHARE BASED PAYMENTS
(a) Employee options
An Executive Share Option Plan operates to provide incentives for key executives. Participation in the plan is at the Board’s discretion.
Details of options issued under the plan shown below (2019: nil).
Balance at
Start of Year
Granted
During the
Year
Exercise
Price
Average
Fair
Value Per
Option
Exercised
During the
Year
Cancelled or
Expired
During the
Year
Balance at
End of Year
Vested and
Exercisable
Grant Date
Expiry Date
2020
20 Aug 2019 30 Jun 20231
07 Nov 2019 30 Jun 2023
—
—
13,046,116
5,105,000
$0.20
$0.20
$0.120
$0.087
Totals
—
18,151,116
$0.111
Weighted average exercise price
$0.20
—
—
—
—
—
13,046,116
5,105,000
—
18,151,116
$0.20
—
—
—
1 On 7 November 2019 the expiry date of these options was changed from 30 June 2032 to 30 June 2023. The modification resulted in a lower fair value than the
original valuation. Under the requirements of AASB 2 the effect of any decrease in fair value is not recognised.
The weighted average fair value of options granted during the year was $0.111 (2019: none granted) and the weighted average remaining
contractual life at 30 June 2020 was 3-years. The values of Executive Options are calculated at the date of grant using a Black Scholes
valuation. The following factors and assumptions were used in determining the fair value of options granted to executives during the year:
Grant Date
Expiry Date
2020
20 Aug 2019 30 Jun 2023
07 Nov 2019 30 Jun 2023
Fair Value
Per Right
Exercise
Price
Price of Shares
at Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
$0.120
$0.087
$0.20
$0.20
$0.16
$0.17
78%
78%
0.92%
0.85%
—
—
(b) Rights to shares — Short Term Incentive Plan
Under the Group’s Short Term Incentive Plan, the Board may issue share rights in lieu of cash payments. The following rights were issued
during the year:
Grant Date
Plan Year End
Balance at
Start of Year
Number of
Rights Granted
Average Fair
Value Per Right
Exercised
During the Year
Cancelled or
Forfeited
Balance at
End of Year
2020
09 Aug 2019 30 Jun 2019
2019
22 Mar 2019 30 Jun 2018
—
—
3,311,771
$0.155
(3,311,771)
1,634,631
$0.130
(1,634,631)
—
—
—
—
The weighted average fair value of share rights issued under the Short Term Incentive Plan during the year was $0.142 (2019: $0.13).
(c) Rights to shares — Long Term Incentive Plan
Under the Group’s Employee Rights Plan, eligible employees may receive rights to shares of Central Petroleum Limited. The rights are
granted in respect of a plan year which commences 1 July each year. The share rights remain unvested until the end of the performance
period which is three years commencing from the start of each plan year. Except in limited circumstances, eligible employees must still be
in the employment of Central Petroleum Limited as at the vesting date for the rights to vest.
Final vesting percentages are determined by a combination of performance hurdles in respect of a combination of absolute total
shareholder return and relative total shareholder return compared to a specific group of exploration and production companies.
The number of rights to be granted to eligible employees is determined based on the maximum long term incentive amount applicable for
each employee, being either a fixed dollar amount or a percentage of the employee’s base salary, divided by the volume weighted average
share price at the start of the plan year.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
85
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
32. SHARE BASED PAYMENTS (CONTINUED)
(c) Rights to shares — Long Term Incentive Plan (continued)
Share based payment expense for the year includes amounts expensed in respect of the following number of rights either granted or
expected to be granted:
Grant Date
Plan Year End
Balance at
Start of Year
Granted
During the Year
Average
Fair Value
Per Right
Exercised
During the Year
Cancelled or
Forfeited
During the Year
Balance at
End of Year
2020
07 Nov 2019 30 Jun 2019
13 Sep 2019 30 Jun 2017
23 Aug 2019 30 Jun 2020
23 Aug 2019 30 Jun 2020
09 May 2019 30 Jun 2019
17 Apr 2019 30 Jun 2019
17 Apr 2019 30 Jun 2019
24 Sep 2019 30 Jun 2019
24 Sep 2019 30 Jun 2019
02 Oct 2018 30 Jun 2016
27 Jun 2018 30 Jun 2018
16 May 2018 30 Jun 2018
16 May 2018 30 Jun 2018
01 Sep 2017 30 Jun 2018
01 Sep 2017 30 Jun 2018
01 Sep 2017 30 Jun 2017
24 Jan 2017 30 Jun 2017
16 Nov 2016 30 Jun 2017
20 Oct 2016 30 Jun 2017
20 Oct 2016 30 Jun 2017
09 Nov 2015 30 Jun 2016
—
—
—
—
791,808
49,321
7,816
5,784,715
366,711
639
135,920
6,562
10,306
5,198,232
232,990
70,000
25,324
2,631,108
6,607,956
338,442
6,666
1,837,109
627,417
398,520
7,405,740
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
$0.119
$0.150
$0.190
$0.155
$0.101
$0.111
$0.150
$0.087
$0.120
$0.067
$0.102
$0.126
$0.175
$0.081
$0.115
$0.082
$0.190
$0.151
$0.106
$0.135
$0.184
—
(430,073)
—
—
—
—
—
—
—
—
—
—
—
—
—
(52,500)
(25,324)
(1,518,532)
(4,275,334)
(319,619)
—
—
(146,644)
(49,812)
(401,273)
(23,266)
—
(5,250)
(482,686)
(44,771)
—
—
—
—
(797,809)
(31,768)
(17,500)
—
(1,112,576)
(1,815,047)
(7,712)
—
1,837,109
50,700
348,708
7,004,467
768,542
49,321
2,566
5,302,029
321,940
639
135,920
6,562
10,306
4,400,423
201,222
—
—
—
517,575
11,111
6,666
Totals
22,264,516
10,268,786
(6,621,382)
(4,936,114)
20,975,806
The weighted average fair value of share rights granted under the Long Term Incentive Plan during the year was $0.150 (2019: $0.088).
The weighted average remaining contractual life of outstanding share rights at the end of the year was 3.6 years (2019: 3.9 years).
The fair values of deferred share rights granted are valued using methodology that takes into account market and peer performance
hurdles. The values Rights are calculated at the date of grant using a Black Scholes valuation model and Monte Carlo simulations and an
agreed comparator group to assess relative total shareholder return. The following factors and assumptions were used in determining the
fair value of rights granted to key management personnel during FY2020:
Grant Date Expiry Date
09 Aug 20191 13 Sep 2024
23 Aug 20192 30 Jun 2024
13 Sep 20193 08 Dec 2022
07 Nov 20194 12 Nov 2024
Fair Value
Per Right
Exercise
Price
Price of Shares
at Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
$0.155
$0.155
$0.150
$0.119
Nil
Nil
Nil
Nil
$0.155
$0.190
$0.200
$0.170
N/A
98%
N/A
95%
N/A
0.70%
N/A
0.94%
—
—
—
—
1 STIP Rights fully vested on issue – valued at market price at grant date.
2 LTIP Rights for plan year commencing 1 July 2019.
3 Adjustment to number of LTIP Rights for plan year commencing 1 July 2016 – valued at the market price of the known vesting %.
4 LTIP rights issued to L Devaney in respect of the plan year commencing 1 July 2018.
86
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
32. SHARE BASED PAYMENTS (CONTINUED)
(c) Rights to shares — Long Term Incentive Plan (continued)
Grant Date
Plan Year End
2019
09 May 2019 30 June 2019
30 June 2019
17 Apr 2019
30 June 2019
17 Apr 2019
30 June 2019
24 Sep 2019
30 June 2019
24 Sep 2019
30 June 2016
02 Oct 2018
27 Jun 2018
30 June 2018
16 May 2018 30 June 2018
16 May 2018 30 June 2018
29 Nov 2017 30 June 2018
30 June 2015
29 Sep 2017
30 June 2018
01 Sep 2017
30 June 2018
01 Sep 2017
30 June 2017
01 Sep 2017
30 June 2016
01 Sep 2017
24 Jan 2017
30 June 2017
16 Nov 2016 30 June 2017
30 June 2017
20 Oct 2016
30 June 2017
20 Oct 2016
30 June 2016
20 Oct 2016
30 June 2016
20 Oct 2016
22 Dec 2015 30 June 2016
03 Dec 2015 30 June 2016
09 Nov 2015 30 June 2016
30 June 2016
14 Oct 2015
30 June 2015
17 Jun 2015
Balance at
Start of Year
Granted
During the Year
Average
Fair Value
Per Right
Exercised
During the Year
Cancelled or
Forfeited
During the Year
Balance at
End of Year
—
—
—
—
—
—
135,920
6,562
10,306
1,835,910
7,041
6,124,904
262,500
70,000
327,000
25,324
6,050,315
7,053,384
372,385
18,517
106,666
1,913,873
6,063
515,083
5,261,487
73,429
791,808
49,321
7,816
5,784,715
366,711
781,438
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
$0.101
$0.111
$0.150
$0.087
$0.120
$0.067
$0.102
$0.126
$0.175
$0.055
$0.097
$0.081
$0.115
$0.082
$0.056
$0.190
$0.151
$0.106
$0.135
$0.135
$0.087
$0.123
$0.165
$0.184
$0.147
$0.074
—
—
—
—
—
(395,964)
—
—
—
—
(7,041)
—
—
—
(161,865)
—
—
—
—
(18,517)
(52,800)
(1,038,000)
(6,063)
(285,881)
(2,565,732)
(73,429)
—
—
—
—
—
(384,835)
—
—
—
(1,835,910)
—
(926,672)
(29,510)
—
(165,135)
—
(3,419,207)
(445,428)
(33,943)
—
(53,866)
(875,873)
—
(222,536)
(2,695,755)
—
791,808
49,321
7,816
5,784,715
366,711
639
135,920
6,562
10,306
—
—
5,198,232
232,990
70,000
—
25,324
2,631,108
6,607,956
338,442
—
—
—
—
6,666
—
—
Totals
30,176,669
7,781,809
(4,605,292)
(11,088,670)
22,264,516
The following factors and assumptions were used in determining the fair value of share rights granted during FY2019:
Grant Date Expiry Date
24 Sep 2018 22 May 2024
02 Oct 20181 Various
22 Mar 20192 10 Apr 2024
Fair Value
Per Right
Exercise
Price
Price of Shares
at Grant Date
Estimated
Volatility
Risk Free
Interest Rate
Dividend
Yield
$0.087
$0.067
$0.130
Nil
Nil
Nil
$0.120
$0.135
$0.130
86%
N/A
N/A
2.33%
N/A
N/A
—
—
—
1 Adjustment to number of LTIP Rights for plan year commencing 1 July 2015 – valued at the market price of the known vesting %.
2 STIP Rights fully vested on issue – valued at market price on issue.
(d) Expenses arising from share-based payment transactions
Total expenses arising from share-based transactions recognised during the year were:
Share Rights issued to employees
2020
$
2019
$
1,937,011
601,897
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
87
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
33. FINANCIAL RISK MANAGEMENT
The Consolidated Entity’s principal financial instruments are cash and short-term deposits. The Consolidated Entity also has other financial
assets and liabilities such as trade receivables, trade payables and borrowings, which arise directly from its operations. The Consolidated
Entity’s risk management objective with regard to financial instruments and other financial assets include gaining interest income and the
policy is to do so with a minimum of risk.
(a) Credit Risk
The credit risk on financial assets of the Consolidated Entity which have been recognised in the balance sheet is generally the carrying
amount, net of any provision for expected credit losses. The Group applies the simplified approach to providing for expected credit losses
prescribed by AASB 9, which permits the use of the lifetime expected loss provision for all trade receivables. Under this method,
determination of the loss allowance provision and expected loss rate incorporates past experience and forward-looking information,
including the outlook for market demand, the current economic environment, and forward-looking interest rates. As the expected loss rate
at 30 June 2020 is nil (2019: nil), no loss allowance provision has been recorded at 30 June 2020 (2019: nil).
The Consolidated Entity trades only with recognised banks and large customers where the credit risk is considered minimal.
Customer credit risk is managed in accordance with the Group’s established policy, procedures and controls. Outstanding customer
receivables are regularly monitored and relate to the Groups’ customers for which there is no history of credit risk or overdue payments.
An impairment analysis is performed at each reporting date on an individual basis for the major customers.
The aging of the Consolidated Entity’s receivables at reporting date was:
Trade and other receivables
Current: 0-30 days
Gross
Expected Credit
Loss Provision
2020
$’000
2019
$’000
2020
$’000
2019
$’000
5,453
7,830
5,453
7,830
—
—
—
—
The receivables at 30 June 2020 relate predominantly to oil and gas sales which have all been received subsequent to year end.
Credit risk also arises in relation to financial guarantees given by the Parent Entity and other non-borrowing Group entities to certain
parties in respect of borrowings by other Group entities (refer Note 25(b)). Such guarantees are only provided in exceptional circumstances
and are subject to specific Board approval.
88
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
33. FINANCIAL RISK MANAGEMENT (CONTINUED)
(b) Liquidity Risk
Prudent liquidity risk management implies maintaining sufficient cash and marketable securities and the availability of funding.
Management monitors rolling forecasts of the Group’s liquidity reserve (comprising the undrawn borrowing facilities below) and cash and
cash equivalents (Note 7) based on expected cash flows. This is carried out at the Group level in accordance with practice and limits set by
the Board of Directors. In addition, the Group’s liquidity management policy involves projecting cash flows, monitoring balance sheet
liquidity ratios against internal and external regulatory requirements and maintaining debt financing plans.
The Group manages its exposure to key financial risks primarily through supervision by the Audit and Risk Committees. The primary
function of these Committees is to assist the Board to fulfil its responsibility to ensure that the Group’s internal control framework is
effective and efficient.
The following are the contractual maturities of financial assets and liabilities:
2020 ($’000)
Financial Assets
Cash and cash equivalents
Trade and other receivables
Other financial assets
Financial Liabilities
Trade and other payables
Interest bearing liabilities
Other financial liabilities
2019 ($’000)
Financial Assets
Cash and cash equivalents
Trade and other receivables
Other financial assets
Financial Liabilities
Trade and other payables
Interest bearing liabilities
Other financial liabilities
(cid:148) 6 Months
6–12 Months
1–5 Years
(cid:149) 5 Years
Contractual
Cash Flow
Carrying
Amount
25,918
5,453
—
31,371
(5,073)
(5,355)
—
—
—
—
—
—
—
2,656
2,656
(214)
(6,227)
—
—
(64,837)
—
(10,428)
(6,441)
(64,837)
17,806
7,830
—
25,636
(6,006)
(12,233)
—
—
—
—
—
—
(4,463)
(2,057)
—
—
2,771
2,771
—
(72,039)
(14,879)
(18,239)
(6,520)
(86,918)
—
—
—
—
—
(143)
—
(143)
—
—
—
—
—
—
—
—
25,918
5,453
2,656
34,027
(5,287)
(76,562)
—
25,918
5,453
2,656
34,027
(5,287)
(71,999)
—
(81,849)
(77,286)
17,806
7,830
2,771
28,407
(6,006)
(88,735)
(16,936)
17,806
7,830
2,771
28,407
(6,006)
(81,730)
(15,849)
(111,677)
(103,585)
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
89
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
33. FINANCIAL RISK MANAGEMENT (CONTINUED)
(c)
Interest Rate Risk
The Consolidated Entity’s exposure to interest rate risk, which is the risk that a financial instrument’s value will fluctuate as a result of
changes in market interest rates and the effective weighted average interest rates on classes of financial assets and financial liabilities, is as
follows:
Weighted
Average
Effective
Interest Rate
Floating
Interest Rate
Fixed Interest
Non-Interest-
Bearing
Total
2020
%
2019
%
2020
$’000
2019
$’000
2020
$’000
2019
$’000
2020
$’000
2019
$’000
2020
$’000
2019
$’000
0.3
—
0.2
—
5.6
—
Financial Assets:
Cash and cash equivalents
Trade and other receivables
Other financial assets
Total Financial Assets
Financial Liabilities:
Trade and other payables
Interest bearing liabilities
Other financial liabilities
Total Financial Liabilities
Net Financial Assets /
(Liabilities)
Interest Rate Sensitivity
1.3
—
0.9
25,918
—
—
17,806
—
—
—
—
1,083
—
—
1,163
—
5,453
1,573
—
7,830
1,608
25,918
5,453
2,656
17,806
7,830
2,771
25,918
17,806
1,083
1,163
7,026
9,438
34,027
28,407
—
6.8
—
—
(70,773)
—
—
(81,730)
—
—
(1,226)
—
(70,773)
(81,730)
(1,226)
—
—
—
—
(5,287)
—
—
(6,006)
—
(15,849)
(5,287)
(71,999)
—
(6,006)
(81,730)
(15,849)
(5,287)
(21,855)
(77,286)
(103,585)
(44,855)
(63,924)
(143)
1,163
1,739
(12,417)
(43,259)
(75,178)
A sensitivity of 10% has been selected as this is considered reasonable given the current level of both short term and long term interest
rates. A 10% movement in interest rates at the reporting date would have increased/(decreased) equity and profit and loss by the amounts
shown below based on the average balance of interest-bearing financial instruments held. This analysis assumes that all other variables
remain constant.
The analysis is performed only on those financial assets and liabilities with floating interest rates and is prepared on the same basis as for
2019.
Profit or Loss
Equity
10% Increase
10% Decrease
10% Increase
10% Decrease
2020 ($’000)
Cash and cash equivalents
Interest bearing liabilities
2019 ($’000)
Cash and cash equivalents
Interest bearing liabilities
7
(397)
23
(558)
(7)
397
(23)
558
—
—
—
—
—
—
—
—
These movements would not have any impact on equity other than retained earnings.
(d) Commodity Risk
The majority of gas sales are made under long term contracts and as such do not contain any commodity risk for the duration of the
contract. The Consolidated Entity is exposed to commodity price fluctuations in respect of recorded crude oil sales and gas sales which are
not subject to long term fixed price contracts. The effect of potential fluctuations is not considered material to balances recorded in these
financial statements. The Board’s current policy is not to hedge crude oil sales. The Board will continue to monitor commodity price risk
and take action to mitigate that risk if it is considered necessary in light of the Group’s overall product sales mix and forecast cash flows.
90
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
33. FINANCIAL RISK MANAGEMENT (CONTINUED)
(d)
Commodity Risk (continued)
In 2019 other financial liabilities included amounts recognised under a Gas Sale & Prepayment Agreement entered into in 2016 whereby the
customer could elect for a financial settlement in lieu of taking physical delivery of gas. In July 2019 the customer novated its rights and
obligations under the contract to a third party and a financial settlement option no longer exists. The balance of the financial liability at the
time of novation was transferred to deferred revenue (see Note 18 and Note 2(b)). Prior to the novation, the financial settlement amount
was either a base price per the agreement, or the weighted average price of gas delivered under any new Gas Sales Agreements (GSA)
entered into by the Consolidated Entity and supplied from the production area, or a combination of both. The first new GSA commenced
June 2017.
Volume Sensitivity
The financial liability is valued based on achieving take or pay volumes under new GSA’s in existence. A sensitivity of 10% has been selected
on the deliverable volumes under the new GSA’s to show the impact on the carrying value:
Profit or Loss
Equity
10% Increase
10% Decrease
10% Increase
10% Decrease
2020 ($’000)
Other financial liabilities
2019 ($’000)
Other financial liabilities
—
—
—
919
—
—
—
—
These movements would not have any impact on equity other than retained earnings.
Price Sensitivity
A sensitivity of 1% of the weighted average gas price under new GSA’s has been selected to show the impact on the carrying value of the
financial liability:
2020 ($’000)
Other financial liabilities
2019 ($’000)
Other financial liabilities
Profit or Loss
Equity
1% Increase
1% Decrease
1% Increase
1% Decrease
—
(158)
—
158
—
—
—
—
These movements would not have any impact on equity other than retained earnings.
(e) Financing Facilities
The Group has a loan facility agreement (Facility) with Macquarie Bank Limited (Macquarie).
Interest costs are based on fixed spreads over the periodic Bank Bill Swap (BBSW) average bid rate. The Facility is structured as a partially
amortising term loan and has a maturity date of 30 September 2021 (2019: 30 September 2020). Repayments comprise fixed quarterly
principal repayments of $1,000,000 along with accrued interest to September 2020 and $2,000,000 per quarter thereafter. The Group does
not have any interest rate hedging arrangements in place.
Under the terms of the Facility, the Group is required to comply with the following two key financial covenants:
1.
2.
The Group Current Ratio is at least 1:1, excluding amounts payable under the Macquarie debt facility and certain liabilities associated
with gas sales agreements with Macquarie Bank.
The Net Present Value with a 10% discount rate (NPV10) of forecasted net cash flow from the Palm Valley, Dingo and Mereenie gas
fields limited by the sales of only Proved Developed Producing reserves, divided by the outstanding loan amount must be greater
than 1:3:1.
The Group remains compliant with these and all other financial covenants under the Facility.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
91
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
33. FINANCIAL RISK MANAGEMENT (CONTINUED)
(f) Currency Risk
The Consolidated Entity’s exposure to currency risk is limited due to its ongoing operations being in Australia and most associated contracts
completed in Australian dollars. A foreign exchange risk arises from oil sales denominated in US dollars and from liabilities denominated in
a currency other than Australian dollars. The Group generally does not undertake any hedging or forward contract transactions as the
exposure is considered immaterial, however, individual transactions are reviewed for any potential currency risk exposure.
At reporting date, the Group had the following exposure to foreign currency risk for balances denominated in US dollars from its continuing
operations, which are disclosed in Australian dollars:
Trade and other receivables
Trade and other payables
2020
$’000
677
(153)
2019
$’000
1,923
(138)
The following table details the Group’s Profit or Loss sensitivity to a 10% increase or decrease in the Australian dollar against the US dollar,
with all other variables held constant. The sensitivity analysis is based on the foreign currency risk exposure at the reporting date.
Australian dollar/ US dollar +10%
Australian dollar/ US dollar -10%
2020
$’000
(62)
75
2019
$’000
(162)
198
These movements would not have any impact on equity other than retained earnings.
(g) Fair Values
The carrying amounts of cash, cash equivalents, financial assets and financial liabilities, approximate their fair values.
34. INTERESTS IN JOINT ARRANGEMENTS
Details of joint arrangements in which the Consolidated Entity has an interest and the name of the party with joint control are as follows:
Principal Activities
Oil & gas production
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration – application
Oil & gas exploration – application
Oil & gas exploration
2020
%
50.00
60.00
60.00
60.00
30.00
30.00
100.00
50.00
50.00
50.00
2019
%
50.00
60.00
60.00
60.00
30.00
30.00
60.00
50.00
50.00
50.00
OL4, OL5 and PL2 Mereenie (Macquarie1)
EP 82 (Santos2)
EP 105 (Santos2)
EP 106 (Santos2)
EP 112 (Santos2)
EP 125 (Santos2)
EP 115 North Mereenie Block (Santos2)
EPA 111 (Santos2)
EPA 124 (Santos2)
ATP 2031 Range Gas Project (IPL3)
1 Macquarie = Macquarie Mereenie Pty Ltd.
2 Santos = Santos Group companies.
3 IPL = Incitec Pivot Limited.
The Joint Arrangements are accounted for based on contributions made to the Joint Operated Arrangements on an accruals basis. The
principal place of business is Australia.
Santos’ right to earn and retain participating interests in each permit is subject to satisfying various obligations in their respective farmout
agreement. The participating interests as stated assume such obligations have been met, or otherwise may be subject to change or
negotiation.
92
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
34. INTERESTS IN JOINT ARRANGEMENTS (CONTINUED)
The share in the assets and liabilities of the joint arrangements where less than 100% interest is held by the Company are included in the
Consolidated Entity’s balance sheet in accordance with the accounting policy described in Note 1(b) under the following classifications:
Current assets
Cash and cash equivalents
Trade and other receivables
Inventory
Other financial assets
Total current assets
Non-current assets
Property, plant and equipment
Right of use assets
Other financial assets
Total non-current assets
Current liabilities
Trade and other payables
Accruals
Lease liabilities
Deferred revenue
Provision for production over-lift
Restoration provision
Total current liabilities
Non-current liabilities
Deferred revenue
Lease liabilities
Provision for production over-lift
Restoration provision
Total non-current liabilities
Net assets
Joint arrangement contribution to loss before tax
Revenue
Other income
Expenses
Profit before income tax
2020
$’000
666
4,243
1,409
—
6,318
52,074
225
301
52,600
1,963
1,531
46
731
712
119
5,102
439
187
3,461
21,433
25,520
28,296
38,541
10
(26,849)
11,702
2019
$’000
510
6,224
1,325
—
8,059
57,519
—
301
57,820
541
1,275
—
731
—
—
2,547
439
—
4,008
19,595
24,042
39,290
42,992
22
(25,909)
17,105
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
93
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2020
35. EVENTS OCCURRING AFTER THE REPORTING PERIOD
Amadeus to Moomba Gas Pipeline
In August, Central announced an agreement to work with Australian Gas Infrastructure Group and Macquarie Mereenie Pty Ltd towards a
FID on a proposed new pipeline to enable Central’s gas to be transported direct to the Moomba gas supply hub and the larger south-
eastern Australian gas markets at a lower cost than existing routes.
Issue of shares
On 18 September 2020, the Company issued 146,215 shares to employee participants in the $1,000.00 Exempt Plan.
Issue and cancellation of share rights
On 18 September 2020, the Company issued 10,179,464 Share Rights pursuant to the Employee Rights Plan. The Company also cancelled
717,033 Share Rights on the same date and a further 211,528 on 23 September 2020.
No other matter or circumstance has arisen between 30 June 2020 and the date of this report that will affect the Group’s operations, result
or state of affairs, or may do so in future years.
94
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
DIRECTORS’ DECLARATION
1.
In the Directors’ opinion:
a) the financial statements and notes set out on pages 45 to 94 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 2020 and of its performance
for the financial year ended on that date;
b) there are reasonable grounds to believe that the Company will be able to pay its debts as and when they become due and
payable; and
c) the financial statements comply with the International Financial Reporting Standards as issued by the International
Accounting Standards Board as disclosed in Note 1(a).
2. This declaration has been made after receiving the declarations required to be made to the Directors in accordance with section
295A of the Corporations Act 2001 (Cth) for the financial year ended 30 June 2020.
3. As at the date of this declaration, there are reasonable grounds to believe that the members of the Closed Group identified in
Note 27 will be able to meet any obligations or liabilities to which they are or may become subject by virtue of the Deed of Cross
Guarantee between the Company and those members of the Closed Group pursuant to ASIC Corporations (Wholly owned
Companies) Instrument 2016/785.
This declaration is made in accordance with a resolution of the Directors of Central Petroleum Limited:
Wrixon Gasteen
Director
Brisbane
24 September 2020
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
95
INDEPENDENT AUDITOR’S REPORT
Independent auditor’s report
To the members of Central Petroleum Limited
Report on the audit of the financial report
Our opinion
In our opinion:
The accompanying financial report of Central Petroleum Limited (the Company) and its controlled
entities (together the Group) is in accordance with the Corporations Act 2001, including:
(a)
giving a true and fair view of the Group's financial position as at 30 June 2020 and of its
financial performance for the year then ended
(b)
complying with Australian Accounting Standards and the Corporations Regulations 2001.
What we have audited
The Group financial report comprises:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
the consolidated balance sheet as at 30 June 2020
the consolidated statement of changes in equity for the year then ended
the consolidated statement of cash flows for the year then ended
the consolidated statement of profit or loss and other comprehensive income for the year then
ended
the notes to the consolidated financial statements, which include a summary of significant
accounting policies
the directors’ declaration.
Basis for opinion
We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under
those standards are further described in the Auditor’s responsibilities for the audit of the financial
report section of our report.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for
our opinion.
Independence
We are independent of the Group in accordance with the auditor independence requirements of the
Corporations Act 2001 and the ethical requirements of the Accounting Professional & Ethical
Standards Board’s APES 110 Code of Ethics for Professional Accountants (including Independence
Standards) (the Code) that are relevant to our audit of the financial report in Australia. We have also
fulfilled our other ethical responsibilities in accordance with the Code.
PricewaterhouseCoopers, ABN 52 780 433 757
480 Queen Street, BRISBANE QLD 4000, GPO Box 150, BRISBANE QLD 4001
T: +61 7 3257 5000, F: +61 7 3257 5999, www.pwc.com.au
Liability limited by a scheme approved under Professional Standards Legislation.
96
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
Our audit approach
An audit is designed to provide reasonable assurance about whether the financial report is free from
material misstatement. Misstatements may arise due to fraud or error. They are considered material if
individually or in aggregate, they could reasonably be expected to influence the economic decisions of
users taken on the basis of the financial report.
We tailored the scope of our audit to ensure that we performed enough work to be able to give an
opinion on the financial report as a whole, taking into account the geographic and management
structure of the Group, its accounting processes and controls and the industry in which it operates.
Materiality
Audit scope
Key audit matters
(cid:120) Our audit focused on where
the Group made subjective
judgements; for example,
significant accounting
estimates involving
assumptions and inherently
uncertain future events.
(cid:120) The Group produces oil and
gas from its interests in fields
in the Northern Territory and
continues to conduct
exploration and evaluation
activities in respect of
tenements located in the
Northern Territory and
Queensland.
(cid:120) Amongst other relevant topics,
we communicated the following
key audit matters to the Audit
and Risk Committee:
(cid:16)(cid:16) Basis of preparation of the
financial report
(cid:16)(cid:16) Recoverability of producing
assets (including goodwill)
and exploration assets
(cid:120)
These are further described in
the Key audit matters section of
our report.
(cid:120)
For the purpose of our audit
we used overall Group
materiality of $1.6 million,
which represents
approximately 1% of the
Group's total assets.
(cid:120) We applied this threshold,
together with qualitative
considerations, to determine
the scope of our audit and the
nature, timing and extent of
our audit procedures and to
evaluate the effect of
misstatements on the financial
report as a whole.
(cid:120) We chose Group total assets
because, in our view, it is the
benchmark against which the
performance of the Group is
most commonly measured and
is a generally accepted
benchmark in the oil and gas
industry for entities at a
similar stage of development.
(cid:120) We utilised a 1% threshold
based on our professional
judgement, noting it is within
the range of commonly
acceptable thresholds.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
97
INDEPENDENT AUDITOR’S REPORT
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)
In assessing the appropriateness of the Group’s going
concern basis of preparation of the financial report, we
performed the following procedures, amongst others:
As described in Note 1 to the financial report, the
financial statements have been prepared by the Group
on a going concern basis, which contemplates that the
Group will continue to meet its commitments, realise
its assets and settle its liabilities in the normal course of
business.
(cid:3)
(cid:120)
Evaluated the appropriateness of the Group's
assessment as to their ability to continue as a
going concern, including whether the level of
analysis is appropriate given the nature of the
Group; checking that the period covered is at
least 12 months from the date of the auditor’s
report; and that relevant information of which
the auditor is aware as a result of the audit has
been considered;
(cid:120) Enquired of management and the board of
directors as to its knowledge of events or
conditions that may cast doubt on the Group's
ability to continue as a going concern;
(cid:120) Assessed the cash flow forecast by evaluating
the reliability of selected underlying data and
considered evidence around key assumptions
in the Group’s cash flow forecasts;
(cid:120)
Performed a sensitivity analysis by varying key
assumptions, including the timing and
amount of expenditure, in the cash flow
forecasts, to assess the impact on financing
facilities utilised in the event that actual
performance varies from that assumed in the
Group’s forecasts;
(cid:120) Obtained an understanding and requested
representations from management and the
Board of Directors regarding their plans for
future action and the feasibility of these plans,
including the availability of alternative sources
of funds, if required;
(cid:120) We evaluated whether, in view of the
requirements of Australian Accounting
Standards, the financial report provides
adequate disclosure on the Group’s going
concern assessment.
Assessing the appropriateness of the Group’s basis of
preparation for the financial report was a key audit
matter due to its importance to the financial report and
the level of judgement involved in assessing future
funding and operational status, in particular with
respect to the Group forecasting future cash flows for a
period of at least 12 months from the date of the
financial report (cash flow forecasts).
98
CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
Key audit matter
How our audit addressed the key audit matter
Recovery of producing assets (including
goodwill) and exploration assets
(Refer to notes 10, 12 & 15)
At 30 June, the Group recognised $3.91 million of
goodwill, $107.85 million of property, plant and
equipment, and $8.72 million of exploration assets on
the consolidated balance sheet.
Producing assets
Goodwill is monitored by management at the level of
the operating segment and has been allocated to the
producing assets cash generating unit (the producing
assets CGU). In line with Australian Accounting
Standards, which require companies to test goodwill for
impairment annually, the Group have performed
impairment tests for the producing assets CGU as at 30
June 2020, and determined the recoverable amount by
using the fair value less cost of disposal (FVLCD)
methodology utilising a discounted cashflow model
(the impairment model). The Group concluded that
there was no impairment of the producing assets cash
generating unit (the CGU assets).
Exploration assets
Each area of interest is reviewed at the end of each
accounting period and accumulated costs written off to
the extent that they will not be recoverable in the future
in line with the requirements of AASB 6 Exploration
for and Evaluation of Mineral Resources. The Group
concluded that there was impairment for two areas of
interest , totalling $0.17 million.
We considered managements assessments into the
recovery of producing assets (including goodwill) and
exploration assets to be a key audit matter given the
significance of the assets to the consolidated balance
sheet, the early stages in the development lifecycle of
these assets, and the significant judgement involved in
determining the cash flow forecasts in the impairment
model.
the Group’s assessment of
To evaluate
the
recoverable amount of the (cid:83)roducing assets CGU, we
performed a number of procedures including the
following:
(cid:120)
Assessed whether the composition of the
Producing assets CGU was consistent with our
knowledge of the Group’s operations,
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
Assessed whether the CGU appropriately
included all directly attributable assets,
liabilities and cash flows,
Considered whether the discounted cash flow
model used to estimate the recoverable
amount of the CGU on a ‘fair value less cost of
disposal’ basis (the impairment model) was
consistent with Australian Accounting
Standards,
Compared the forecast cash flows used in the
impairment model to the most recent budgets
and business plans approved by the board,
Considered whether the forecast cash flows in
the impairment model were reasonable and
based upon supportable assumptions, by
comparing:
o
o
oil and gas price data used in the
impairment model to industry
forecasts, and
forecast oil and gas production over
the life of fields to the Group’s most
recent reserves and resources
statement
Assessed, with assistance from PwC valuation
experts that the post-tax nominal discount
rate applied in the model reflects the risks of
the CGU
evaluated the Group’s historical ability to
forecast future cash flows by comparing
budgets with the reported actual results for
the past three years,
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 99
INDEPENDENT AUDITOR’S REPORT
Key audit matter
How our audit addressed the key audit matter
(cid:120)
(cid:120)
performed tests, on a sample basis of the
mathematical accuracy of the impairment
model calculations,
evaluated the adequacy of disclosures made in
note 15 of the financial statements, including
those regarding key assumptions used in the
impairment assessment in light of the
requirements of the Australian Accounting
Standards.
To evaluate the Group’s assessment of the recoverable
amount of exploration assets, we performed a number
of procedures including the following:
(cid:120) met with key operational and finance staff to
develop an understanding of the current
status and future intention for each area of
interest,
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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
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.
evaluated the adequacy of the impairment
charge, in light of the requirements of the
Australian Accounting Standards.
Other information
The directors are responsible for the other information. The other information comprises the
information included in the annual report for the year ended 30 June 2020, 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.
100 CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
In connection with our audit of the financial report, our responsibility is to read the other information
and, in doing so, consider whether the other information is materially inconsistent with the financial
report or our knowledge obtained in the audit, or otherwise appears to be materially misstated.
If, based on the work we have performed on the other information that we obtained prior to the date of
this auditor’s report, we conclude that there is a material misstatement of this other information, we
are required to report that fact. We have nothing to report in this regard.
Responsibilities of the directors for the financial report
The directors of the Company are responsible for the preparation of the financial report that gives a
true and fair view in accordance with Australian Accounting Standards and the Corporations Act 2001
and for such internal control as the directors determine is necessary to enable the preparation of the
financial report that gives a true and fair view and is free from material misstatement, whether due to
fraud or error.
In preparing the financial report, the directors are responsible for assessing the ability of the Group to
continue as a going concern, disclosing, as applicable, matters related to going concern and using the
going concern basis of accounting unless the directors either intend to liquidate the Group or to cease
operations, or have no realistic alternative but to do so.
Auditor’s responsibilities for the audit of the financial report
Our objectives are to obtain reasonable assurance about whether the financial report as a whole is free
from material misstatement, whether due to fraud or error, and to issue an auditor’s report that
includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an
audit conducted in accordance with the Australian Auditing Standards will always detect a material
misstatement when it exists. Misstatements can arise from fraud or error and are considered material
if, individually or in the aggregate, they could reasonably be expected to influence the economic
decisions of users taken on the basis of the financial report.
A further description of our responsibilities for the audit of the financial report is located at the
Auditing and Assurance Standards Board website at:
https://www.auasb.gov.au/admin/file/content102/c3/ar1_2020.pdf. This description forms part of
our auditor's report.
Report on the remuneration report
Our opinion on the remuneration report
We have audited the remuneration report included in pages 30 to 43 of the directors’ report for the
year ended 30 June 2020.
In our opinion, the remuneration report of Central Petroleum Limited for the year ended 30 June
2020 complies with section 300A of the Corporations Act 2001.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
101
INDEPENDENT AUDITOR’S REPORT
Responsibilities
The directors of the Company are responsible for the preparation and presentation of the
remuneration report in accordance with section 300A of the Corporations Act 2001. Our responsibility
is to express an opinion on the remuneration report, based on our audit conducted in accordance with
Australian Auditing Standards.
PricewaterhouseCoopers
Tim Allman
Partner
Brisbane
24 September 2020
102 CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
ASX ADDITIONAL INFORMATION
DETAILS OF QUOTED SECURITIES AS AT 21 SEPTEMBER 2020
Top holders
The 20 largest registered holders of the quoted securities as at 21 September 2020 were:
Name
Norfolk Enchants Pty Ltd
UBS Nominees Pty Ltd
Fanchel Pty Ltd
Mr Christopher Ian Wallin + Ms Fiona Kay McLoughlin + Mrs Sylvia Fay Bhatia
17,571,648
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Macquarie Bank Limited
Citicorp Nominees Pty Limited
Brazil Farming Pty Ltd
Mr Raymond Driscoll + Mrs Karyn Driscoll + Mr Jarrod Driscoll
Kensington Capital Partners Pty Ltd
Chembank Pty Limited
JH Nominees Australia Pty Ltd
Mr Philip Gasteen
Mr William Bambling + Mrs Joyce Bambling
Mr Donald Leonard Cottee
Mr Stuart Francis Howes
Mr James Donald Bruce Cochrane + Mrs Joan Elizabeth Cochrane
17-19 Chembank Pty Limited
17-19 Dynasty Peak Pty Ltd
17-19 Justwright Investments Pty Ltd
20
Garmi Holdings Pty Ltd
No. of Shares
%
35,791,682
29,906,170
19,000,000
14,166,667
13,961,704
13,500,000
8,936,608
7,923,341
7,000,000
6,700,000
6,501,255
6,300,000
5,581,344
5,501,001
5,000,001
5,000,000
5,000,000
5,000,000
4,000,000
4.95
4.13
2.63
2.43
1.96
1.93
1.87
1.24
1.10
0.97
0.93
0.90
0.87
0.77
0.76
0.69
0.69
0.69
0.69
0.55
DISTRIBUTION SCHEDULE
A distribution schedule of the number of holders in each class of equity securities as at 21 September 2020 was:
Total 222,341,421
30.73
Size of Holding
1 - 1,000
1,001 -5,000
5,001 - 10,000
10,001 - 100,000
100,001 - Over
Total
Number of Holders
Listed Fully
Paid Shares
Unlisted
Share Rights
Unlisted
Options
758
1,889
1,083
2,760
1,007
7,497
3
8
11
45
30
97
—
—
—
—
5
5
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
103
ASX ADDITIONAL INFORMATION
SUBSTANTIAL SHAREHOLDERS
Substantial shareholders as disclosed by notices received by the Company as at 21 September 2020 with holdings of 5% or more of the
total votes attached to the voting shares or interests in the Entity:
Holder
Troy Harry
Units
46,683,341
UNMARKETABLE PARCELS
Holdings less than a marketable parcel of ordinary shares (being 3,847 shares as at 21 September 2020):
Holders
2,150
Units
3,340,858
VOTING RIGHTS
Subject to any rights or restrictions for the time being attached to any class or classes of shares, at meetings of shareholders or classes of
shareholders:
•
•
•
each shareholder entitled to vote may vote in person or by proxy, attorney or representative of a shareholder;
on a show of hands, every person present who is a shareholder or a proxy, attorney or representative of a shareholder has one vote;
and
on a poll, every person present who is a shareholder shall, in respect of each fully paid share held by him, or in respect of which he is
appointed a proxy, attorney or representative, have one vote for their share, but in respect of partly paid shares, shall have such
number of votes being equivalent to the proportion which the amount paid (not credited) is of the total amounts paid and payable in
respect of those shares (excluding amounts credited).
ON-MARKET BUY-BACK
There is no current on-market buy-back of the Company’s securities.
CORPORATE GOVERNANCE STATEMENT
Central Petroleum Limited and its Board are committed to achieving and demonstrating high standards of corporate governance. The
Company has reviewed its corporate governance practices against the Corporate Governance Principles and Recommendations (3rd edition)
published by the ASX Corporate Governance Council.
The 2020 Corporate Governance Statement is dated as at 30 June 2020 and reflects the corporate governance practices in place
throughout the 2020 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/.
104 CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
INTERESTS IN PETROLEUM PERMITS AND PIPELINE
LICENCES AT THE DATE OF THIS REPORT
PERMITS AND LICENCES GRANTED
Tenement
Location
CTP Consolidated Entity
Other JV Participants
Operator
Registered
Interest (%)
Beneficial
Interest (%)
Participant
Name
Beneficial
Interest (%)
EP82 (excl. EP82 Sub-Blocks) 1 Amadeus Basin NT
EP82 Sub-Blocks
Amadeus Basin NT
Santos
Central
EP105
EP112 1
EP115 (excl. EP115 North
Mereenie Block)
Amadeus/Pedirka Basin NT
Santos
Amadeus Basin NT
Amadeus Basin NT
EP115 North Mereenie Block2 Amadeus Basin NT
EP125
OL3 (Palm Valley)
OL4 (Mereenie)
OL5 (Mereenie)
L6 (Surprise)
L7 (Dingo)
RL3 (Ooraminna)
RL4 (Ooraminna)
ATP909
ATP911
ATP912
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Georgina Basin QLD
Georgina Basin QLD
Georgina Basin QLD
ATP2031 (Range Gas Project)
Surat Basin QLD
60
100
60
30
100
60
30
100
50
50
100
100
100
100
100
100
100
50
60
100
60
30
100
100
30
100
50
50
100
100
100
100
100
100
100
50
Santos QNT Pty Ltd (Santos)
Santos
Santos
Santos
Macquarie Mereenie Pty Ltd
(Macquarie Mereenie)
Macquarie Mereenie
40
40
70
70
50
50
Incitec Pivot Queensland Gas Pty Ltd
50
Santos
Central
Santos
Santos
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
PERMITS AND LICENCES UNDER APPLICATION
Tenement
Location
CTP Consolidated Entity
Other JV Participants
Operator
Registered
Interest (%)
Beneficial
Interest (%)
Participant
Name
Beneficial
Interest (%)
EPA92
EPA111
EPA120
EPA124 3
EPA129
EPA130
EPA131 4
EPA132
EPA133 5
EPA137
EPA147
EPA149
EPA152 3
EPA160
EPA296
Wiso Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Wiso Basin NT
Pedirka Basin NT
Pedirka Basin NT
Georgina Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Wiso Basin NT
Wiso Basin NT
Central
Santos
Central
Santos
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
50
100
50
100
100
0
100
100
100
100
100
100
100
100
Santos
Santos
50
50
PIPELINE LICENCES
Pipeline Licence
Location
CTP Consolidated Entity
Other JV Participants
Operator
Registered
Interest (%)
Beneficial
Interest (%)
Participant
Name
Beneficial
Interest (%)
PL2
PL30
Amadeus Basin NT
Amadeus Basin NT
Central
Central
50
100
50
100
Macquarie Mereenie
50
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 105
INTERESTS IN PETROLEUM PERMITS AND PIPELINE
LICENCES AT THE DATE OF THIS REPORT
Notes:
1
2
3
4
5
As announced on 16 July 2020, prior to 31 July 2021 Santos can elect that Central be carried for the first $3 million of Dukas-1 well costs. In return for a
carry by Santos and if Santos so elects, Central will transfer 30% equity in EP82 (excluding the Orange prospect) to Santos. Should Santos not carry
Central in exchange for the option to have 30% equity in EP82, its interest in EP112 (including Dukas-1 well) will decrease from 70% to 55% (Central’s
interest will increase from 30% to 45%).
On 12 December 2019 Central received notice from Santos of its intention to withdraw from EP115 North Mereenie Block effective 31 January 2020.
On 22 March 2018 (in respect EPA124) and on 23 March 2018 (in respect of EPA152) Central received notice from the NT Department of Primary
Industry and Resources that EPA124 and EPA152, as applicable, had been placed in moratorium for a period of 5-years from 6 December 2017 until
6 December 2022.
The exploration permit application has been disposed. Transfer of the registered interest is awaiting the grant of an exploration permit.
This exploration permit application was placed into moratorium on 22 October 2015 for a five (5) year period ending on 22 October 2020.
106 CENTRAL PETROLEUM LIMITED 2020 ANNUAL REPORT
CORPORATE DIRECTORY
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS
Mr Stuart Baker BE(Elec), MBA, AICD, Non-Executive Director
Mr Leon Devaney BSc MBA, Managing Director and Chief Executive Officer
Dr Julian Fowles PhD, BSc (Hons), GDipAFI, GAICD, Non-Executive Director
Mr Wrixon F Gasteen BE(Mining) (Hons), MBA (Distinction), Non-Executive Director and Chairman
Ms Katherine Hirschfeld AM, BE(Chem), HonFIEAust, FTSE, FIChemE, CEng, FAICD, Non-Executive Director
Dr Agu Kantsler BSc (Hons), PhD, GAICD, FTSE, Non-Executive Director
Mr Michael (Mick) McCormack BSurv, GradDipEng, MBA, FAICD, Non-Executive Director
GROUP GENERAL COUNSEL AND COMPANY SECRETARY
Mr Daniel White LLB, BCom, LLM
REGISTERED OFFICE
Level 7, 369 Ann Street, Brisbane, Queensland 4000
+61 7 3181 3800
Telephone:
Facsimile:
+61 7 3181 3855
www.centralpetroleum.com.au
AUDITORS
PricewaterhouseCoopers
480 Queen Street, Brisbane, Queensland 4000
BANKERS
ANZ Banking Group
111 Eagle Street, Brisbane, Queensland 4000
SHARE REGISTER
Computershare Investor Services Pty Limited
Level 1, 200 Mary Street, Brisbane, Queensland 4000
Telephone:
Telephone:
Facsimile:
www.computershare.com.au
1300 552 270
+61 3 9415 4000
+61 3 9473 2500
STOCK EXCHANGE LISTING
Central Petroleum Limited shares are listed on the Australian Securities Exchange under the code CTP.
2020 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
107
(cid:38)(cid:72)(cid:81)(cid:87)(cid:85)(cid:68)(cid:79) (cid:51)(cid:72)(cid:87)(cid:85)(cid:82)(cid:79)(cid:72)(cid:88)(cid:80) (cid:47)(cid:76)(cid:80)(cid:76)(cid:87)(cid:72)(cid:71)
(cid:36)(cid:38)(cid:49) (cid:19)(cid:27)(cid:22) (cid:21)(cid:24)(cid:23) (cid:22)(cid:19)(cid:27)
(cid:43)(cid:72)(cid:68)(cid:71) (cid:50)(cid:73)(cid:73)(cid:76)(cid:70)(cid:72)
(cid:47)(cid:72)(cid:89)(cid:72)(cid:79) (cid:26)(cid:15) (cid:22)(cid:25)(cid:28) (cid:36)(cid:81)(cid:81) (cid:54)(cid:87)(cid:85)(cid:72)(cid:72)(cid:87)
(cid:37)(cid:85)(cid:76)(cid:86)(cid:69)(cid:68)(cid:81)(cid:72)(cid:15) (cid:52)(cid:79)(cid:71) (cid:23)(cid:19)(cid:19)(cid:19)
(cid:36)(cid:88)(cid:86)(cid:87)(cid:85)(cid:68)(cid:79)(cid:76)(cid:68)
(cid:51)(cid:82)(cid:86)(cid:87)(cid:68)(cid:79) (cid:36)(cid:71)(cid:71)(cid:85)(cid:72)(cid:86)(cid:86)
(cid:42)(cid:51)(cid:50) (cid:37)(cid:82)(cid:91) (cid:21)(cid:28)(cid:21)
(cid:37)(cid:85)(cid:76)(cid:86)(cid:69)(cid:68)(cid:81)(cid:72)(cid:15) (cid:52)(cid:79)(cid:71) (cid:23)(cid:19)(cid:19)(cid:20)
(cid:36)(cid:88)(cid:86)(cid:87)(cid:85)(cid:68)(cid:79)(cid:76)(cid:68)
(cid:40)(cid:80)(cid:68)(cid:76)(cid:79)
(cid:76)(cid:81)(cid:73)(cid:82)(cid:35)(cid:70)(cid:72)(cid:81)(cid:87)(cid:85)(cid:68)(cid:79)(cid:83)(cid:72)(cid:87)(cid:85)(cid:82)(cid:79)(cid:72)(cid:88)(cid:80)(cid:17)(cid:70)(cid:82)(cid:80)(cid:17)(cid:68)(cid:88)
(cid:90)(cid:90)(cid:90)(cid:17)(cid:70)(cid:72)(cid:81)(cid:87)(cid:85)(cid:68)(cid:79)(cid:83)(cid:72)(cid:87)(cid:85)(cid:82)(cid:79)(cid:72)(cid:88)(cid:80)(cid:17)(cid:70)(cid:82)(cid:80)(cid:17)(cid:68)(cid:88)