2019
(cid:0) (cid:2) (cid:2) (cid:3) (cid:0) (cid:4)
(cid:5) (cid:6) (cid:7) (cid:8) (cid:5) (cid:9)
Central Petroleum Limited
ACN 083 254 308
TABLE OF CONTENTS
CORPORATE DIRECTORY ............................................................................................................................................ 1
CHAIRMAN’S LETTER ................................................................................................................................................. 2
CHIEF EXECUTIVE OFFICER’S LETTER .......................................................................................................................... 3
DIRECTORS’ REPORT ................................................................................................................................................. 4
AUDITOR’S INDEPENDENCE DECLARATION ............................................................................................................. 42
FINANCIAL REPORT ................................................................................................................................................. 43
CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME ...................................... 44
CONSOLIDATED STATEMENT OF FINANCIAL POSITION ............................................................................................ 45
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY ............................................................................................. 46
CONSOLIDATED STATEMENT OF CASH FLOWS ......................................................................................................... 47
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS ........................................................................................ 48
DIRECTORS’ DECLARATION ...................................................................................................................................... 95
INDEPENDENT AUDITOR’S REPORT ......................................................................................................................... 96
ASX ADDITIONAL INFORMATION .......................................................................................................................... 102
CORPORATE GOVERNANCE STATEMENT ................................................................................................................ 103
INTERESTS IN PETROLEUM PERMITS AND PIPELINE LICENCES AT THE DATE OF THIS REPORT ................................ 104
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
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
GROUP GENERAL COUNSEL AND JOINT COMPANY SECRETARY
Mr Daniel C M White LLB, BCom, LLM
JOINT COMPANY SECRETARY
Mr Joseph P Morfea FAIM, GAICD
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.
1
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
CHAIRMAN’S LETTER
Dear Fellow Shareholders
There is little doubt that the past year will be remembered as a watershed year for Central Petroleum. Many years of strategic positioning
and successfully executing on that strategy have started to bear fruit.
Impact of NGP commissioning
Our expanded gas production facilities at Mereenie and Palm Valley, completed on time and within our funding, are now supplying gas to
customers on the gas-short eastern seaboard via the new Northern Gas Pipeline which was commissioned in January. Contracted sales
volumes have almost tripled since January and the resulting cash flow has been applied to reducing debt and provides an operating cash flow
to help unlock the enormous potential of our exploration portfolio.
The production base re-positions Central as a credible, and not insignificant, supplier to gas markets in both the Northern Territory and the
eastern seaboard. Quality conventional assets with low operating costs, combined with a buoyant gas market mean that our gas can be
supplied profitably at competitive prices to customers in Queensland and the Northern Territory.
Exploration – Dukas and Range
With this stable base to underpin us, our next phase of exploration activity has already begun to provide a glimpse of the value that could lie
within our asset portfolio. This will require significant investment. The early signs from the Dukas-1 well in the Amadeus Basin can only
increase the likelihood of a huge gas play in the basin.
The immediate success at the Range project in the heart of Queensland’s proven coal seam gas province demonstrates what our team can
achieve in a short timeframe, with 2C gas resources certified within 12 months from the award of the tenement. This is a clear example of
the positive impact that Government policy can have in alleviating the east coast gas market shortages and provides us with a material
development-ready gas resource adjacent to transportation infrastructure.
Stakeholder Engagement and Climate Change
Stakeholder engagement remains a key focus for us. We thank the traditional owners for working with us over the past year. Our relations
with the stakeholders in our areas of operations are important and our emphasis on employing local people and traditional owners continues
to deliver positive outcomes for the communities touched by our operations.
This year we established a Community Affairs Committee as a Board Committee. The Committee elected Mr Bob Liddle OAM, a Traditional
Owner originally from the Alice Springs region. Our whole Board visited and met with the Traditional Owners at Santa Teresa, Mereenie and
Palm Valley.
At Central we recognise that we don’t have all the answers to solve the Global Climate Change challenge. However, we are a supplier of a
transition fuel significantly lower in CO2 emissions than coal, and a highly sought after bridge between coal and renewables to reinforce a
more stable electricity and energy system in the Northern Territory and on the East Coast.
Board & Management
The achievements of the past year are a testament to the vision of many at Central Petroleum over several years. It has not been an easy
year corporately – the growing pains have resulted in changes at management and Board levels. We have seen the departure of influential
characters, and particularly recognise Richard Cottee for his energy, advocacy and strategic courage in setting Central Petroleum on its
current course. More recently we have accepted the resignation of Martin Kriewaldt as Chairman and thank him for his efforts in guiding the
company through this transition.
I firmly believe that we emerge from the past year a far stronger and more valuable company. Certainly, the broader market is starting to
recognise this with the Company’s share price recently breaking free of the restrictive price range of recent years. We have built an
experienced and capable management team, led by a very talented Managing Director, Leon Devaney.
Our new Board offers a diverse range of industry-specific experience. We welcomed Stuart Baker, Kathy Hirschfeld and Julian Fowles to the
Board this year and I wholeheartedly recommend them for election at this year’s AGM. The Board is implementing the best in Corporate
Governance practices and transparency.
I see this as the beginning of a new era for Central. We appreciate the support of our shareholders during this year of transformation and
enter the next year with a determination to learn from the past. Your new Board fully acknowledges that trust between the Company and
its stakeholders is a function of transparency and stakeholder engagement – and we will be working to deliver.
I am confident that with stability at Board level and Leon’s committed management team, in the coming year we will make significant
progress in implementing our near term exploration programme to unlock further value from Central’s impressive asset portfolio.
Wrixon Gasteen, Chairman
25 September 2019
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
2
CHIEF EXECUTIVE OFFICER’S LETTER
Dear Fellow Shareholders
In my Letter to Shareholders for the 2018 Annual Report, I highlighted the immediate challenges and fundamental changes facing the
Company this time last year. We were focused on delivering our Gas Acceleration Programme (GAP) in time to meet significant firm gas
supply commitments that were tied to the commencement of the Northern Gas Pipeline (NGP). At the same time, we were preparing for a
step change increase in the level of operations and planning for a new future as an E&P company with exploration and production assets
now unconstrained by market.
Today we can look back at the last 12 months having not only delivered those core objectives, but in doing so successfully emerging as a
company much more capable of delivering growth and shareholder value. Commencement of the NGP on 3 January 2019 was the catalyst,
connecting for the first time our recently acquired production assets and vast exploration portfolio in the Northern Territory to the east coast
gas market. Sales nearly tripled, leading to a strong 2nd half FY2019 operating cash flow. We strengthened our balance sheet through
accelerated debt repayments, with net gearing already down to around 32% in September 2019. For the first time in the history of Central,
we are operating from a foundation of new financial optionality.
Increased sales are only part of the story. In the midst of this financial and operational transformation, we reignited a core opportunity to
create a step-change in shareholder wealth - exploration of our dominant position in the Amadeus Basin, one of Australia’s most significant
underexplored onshore basins with five proven hydrocarbon systems and long-term production history.
First, the Dukas-1 exploration well was drilled to within near proximity of the prognosed primary target, before being suspended due to
excessive formation pressures. There were two positive indicators relating to an effective seal and a working hydrocarbon system, so these
were encouraging results, notwithstanding the delay resulting from the technically difficult drilling conditions. It remains a pure exploration
play, but under a success scenario it will be a game-changer for Central and potentially the east coast gas market. We continue to work
closely with operator, Santos, whose technical input and financial contribution have been critical to the Dukas programme. A forward plan
for the well will be outlined as soon as it is fully considered by the Joint Venture.
Second, and less visible than Dukas-1, we made key changes to our exploration team, including a new GM Exploration. Over the past six
months, this team has been undertaking a full portfolio review using additional and updated data and analysis to progress a near-term
exploration plan, including attractive drill-ready prospects that don’t require further analysis. In addition, and a first for Central, the team
initiated a basin-wide play-based analysis so that we can strategically approach a long list of less-mature, but potentially company-changing,
oil and gas targets. This work is fundamental to successfully unlocking the huge potential in Central’s large and complex exploration portfolio.
More recently, the Range gas project (ATP 2031) exploration programme provided a massive shot of momentum for the Company. With a
maiden 2C resource far exceeding our high-side expectations at 270PJ (135PJ net to Central), the Range gas project could approximately
double our reserve base in the heart of the east coast gas market. The Range gas project is emerging as a major new asset for Central, with
the significance of this exploration result becoming increasingly apparent as we accelerate toward a final investment decision (FID) in early
2021 in conjunction with our partner Incitec Pivot.
The year was not without setbacks, detours and “opportunities to learn”. Lower than anticipated field production at Palm Valley, a
disappointing result from our Mereenie appraisal well (WM26) and suspension in our Dukas-1 drilling campaign being some obvious
examples. Safety and environment remain priorities for the Company. Although this year’s results did not meet our internal benchmarks,
we have implemented several new health, safety and environment initiatives and processes in order to improve our performance. There was
also significant change internally, including four Board members replaced and my appointment as CEO in February. Whilst challenges and
changes of this nature could easily trip up small companies trying to deliver across multiple and complex objectives, we maintained
momentum and continuity through the year.
Looking forward to the next 12 months our focus will be on driving value from our operating assets, implementing a well-informed exploration
strategy and development planning for Project Range. These are not easily-achieved objectives, particularly for a junior E&P Company, but
with our executive team now complete with very experienced professionals, we move forward with renewed confidence that we can punch
well above our weight, much as we have done over the past 12 months. The achievements to date are a result of the dedication of our staff
here at Central, and I extend my thanks to our team for their tireless efforts in delivering the strategy.
Capital is naturally a key consideration in our forward plans. New exploration, appraisal and development all require capital. We have already
demonstrated that we can effectively utilise project finance (debt) to minimise any equity requirements. Fortunately, our strengthened
financial position offers us a level of financial optionality we have never had before. Whilst the equity market appears open to quality oil and
gas investments, we have other viable equity alternatives, including application of cash flow from operations, potential sell-down of a
minority interest in our operating or development assets, strategically farming-out exploration activity with a promote, and structured
pre-sale agreements. Ultimately, we will seek the most effective combination of funding options to drive shareholder value from growth.
In closing, I’d like to take this opportunity to thank shareholders for their trust, patience and continued support. After the last 12 months,
Central has emerged as a much stronger company, with a clear vision and growing momentum to write a new and very rewarding chapter
for our shareholders.
Leon Devaney, CEO
25 September 2019
3
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
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 2019.
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 (appointed 7 December 2018)
Mr Leon Devaney (appointed 14 November 2018)
Dr Julian Fowles (appointed 28 June 2019)
Mr Wrixon Gasteen (Chairman)
Ms Katherine Hirschfeld AM (appointed 7 December 2018)
Former Directors:
Mr Richard Cottee (resigned 5 February 2019)
Mr Martin Kriewaldt (resigned 2 September 2019)
Dr Peter Moore (resigned 13 November 2018)
Dr Sarah Ryan (resigned 13 November 2018)
Mr Timothy Woodall (resigned 29 September 2018)
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 (2018: $Nil). No recommendation for payment of dividends has been made.
OPERATING AND FINANCIAL REVIEW
Granted Petroleum Production and Retention Licences in which the Company has an interest.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
4
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Operating Highlights
The Company’s achievements for the year were as follows:
•
•
Second half gas sales volumes increased 150% and total sales revenue increased 96% over the first half. Year on year, a 111%
increase in gas sales volumes and a 70% increase in total sales revenue;
Palm Valley gas field successfully restarted, although at lower than anticipated rates resulting in reduced reserves and lower
production plateaus;
Palm Valley 13 well successfully drilled to 2,242 metres and tied into production facilities in May 2019;
•
• West Mereenie 26 appraisal well was successfully drilled but encountered minimal gas flow due to mineralisation. Material 2C
resources are currently booked in the Stairway formation, which overlies the existing production zones. Evaluation of alternative
approaches to recover gas from the Stairway formation remains ongoing;
•
The Queensland Government formally awarded ATP 2031 to Central’s wholly owned subsidiary, Central Petroleum Eastern Pty Ltd,
for a period of 12 years. The permit lies within the north-eastern Walloon Coals Fairway, surrounded by acreage held by QGC,
Arrow and APLNG:
o
o
o
Partnered with Incitec Pivot (IPL) as 50% joint venturer in the permit, with IPL carrying the first $20 million of exploration
costs;
Range 4 well spudded on 30 June 2019 as the first in a four well exploration programme in ATP 2031 (Incitec Pivot free
carry for first $20 million); and
Certified 270PJ of 2C gas resource (135PJ net to Central) in ATP 2031 after completing the four well exploration
programme subsequent to year end;
• Mereenie Expansion Project was successfully delivered on schedule with firm plant capacity of 44TJ/day;
•
•
Sales through the Northern Gas Pipeline commenced January 2019; and
Santos elected to proceed to Stage 3 of the Southern Amadeus farmout and the Dukas 1 exploration well in EP 112 spudded
on 16 April 2019 reaching a depth of 3,391m at 30 June 2019, and subsequently suspended at 3,704m after encountering
hydrocarbon-bearing gas from an overpressured zone close to the primary target.
Financial Review
The Consolidated Entity had an operating loss after income tax for the year ended 30 June 2019 of $14.5 million (2018: loss of $14.1 million).
The above result was after expensing exploration costs of $15.8 million (2018: $8.8 million) largely associated with the drilling of the Palm
Valley 13 well which was successfully tied-in to production during the year. The Group’s policy is to expense all exploration costs as incurred.
The connection of the Group’s gas fields to east coast gas markets through the Northern Gas Pipeline (NGP) on 3 January 2019 has resulted
in a 105% increase in earnings before interest, tax, depreciation, amortisation and exploration (EBITDAX) from $11.0 million in 2018 to
$22.5 million in 2019. The table below shows key metrics for the Group based on a comparison of first half and second half performance for
2019, which clearly highlights this inflection point, as well as a comparison to full year 2018.
Key Metrics
Natural Gas (TJ)
Net Sales Volumes
-
-
Sales Revenue ($ ‘000)
Oil & Condensate (Bbls)
Gross Profit ($ ‘000)
EBITDAX1 ($ ‘000)
EBITDA2 ($’000)
EBIT3 ($ ‘000)
Statutory Loss after tax ($ ‘000)
Net cash inflow/(outflow) from
Operations4 ($’000)
Capital expenditure5 ($ ‘000)
1st Half
2019
2nd Half
2019
Total
2019
Total
2018
$ Change
(Year)
% Change
(Year)
2,921
43,728
20,022
5,825
2,764
(10,877)
(15,231)
(19,077)
(14,479)
7,308
53,664
39,336
23,164
19,782
17,621
9,279
4,551
16,944
10,229
97,392
59,358
28,989
22,546
6,744
(5,952)
(14,526)
2,465
12,672
3,516
16,188
4,842
105,619
34,939
16,235
11,010
2,221
(5,813)
(14,076)
5,173
4,668
5,387
(8,227)
24,419
12,754
11,536
4,523
(139)
(450)
(2,708)
11,520
111%
(8)%
70%
79%
105%
204%
(2)%
(3)%
(52%)
247%
Notes:
1
2
3
4
5
EBITDAX is Earnings before Interest, Tax, Depreciation, Amortisation and Exploration costs (refer reconciliation below).
EBITDA is Earnings before Interest, Tax, Depreciation and Amortisation.
EBIT is Earnings before Interest and Taxation.
Cashflow from Operations includes cash outflows associated with Exploration activities.
Capital expenditure on tangible assets.
5
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Reconciliation of statutory loss before tax to EBITDAX
Statutory loss before tax
Finance costs
EBIT
Depreciation and amortisation
EBITDA
Exploration expenses
EBITDAX
Sales volumes
2019
$
2018
$
(14,526,414)
(14,076,129)
8,574,831
(5,951,583)
12,695,238
6,743,655
15,802,075
22,545,730
8,263,308
(5,812,821)
8,033,092
2,220,271
8,790,052
11,010,323
Gas volumes in 2019 increased 111% from 2018, taking advantage of the new NGP connection. The Palm Valley gas field was successfully
restarted in October 2018 and the Mereenie facility upgrade was completed on schedule resulting in a 44 TJ/day firm plant capacity
(100% JV).
Gas sales from the Dingo field did not achieve full contracted volumes as the customer continued to take gas below the annual contract
quantity, resulting in an annual take or pay receipt of $5.1 million.
Sales revenue
Sales revenue increased 70% reflecting the upgraded field capacity and resulting increased gas volumes sold through the NGP. Realised oil
prices were up 11% on 2018 but were partly offset by lower volumes.
Sales revenue does not include receipts from take or pay contracts until such time as gas is delivered or forfeited by the buyer. During the
year, the Company received take or pay payments of $5.2m in respect of the 2018 calendar year which have not been reflected in revenue.
Additional Information:
1 Mereenie oil converted at 5.816 GJ/BOE
2
Central had no production prior to April 2014
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
6
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Gross Profit
Gross profit from operations increased 79% year on year as increased production provided increased economies of scale to production
operations.
Depreciation and Amortisation
Non-cash depreciation and amortisation costs increased from $8.0 million to $12.7 million, reflecting the increase in production and larger
depreciable asset base following the Gas Acceleration Program (GAP).
Capital Expenditure
The increase in capital expenditure was a result of the investment in the GAP to expand capacity in time to meet the NGP connection as well
as the successful tie in of the Palm Valley 13 well to the Palm Valley production facilities.
Net Assets/Liabilities
At 30 June 2019 the Group had a net liability position of $5.6 million compared to a net asset position at 30 June 2018 of $7.1 million. The
net liability position improved from $11.2 million at 31 December 2018, reflecting the impact of the NGP commissioning resulting in increased
operating cash flows.
Over the year cash balances have reduced by $9.4 million as the funds remaining from the 2017 capital raising were applied to exploration
activities, mainly the drilling of Palm Valley 13 which was successfully tied into production.
Included in liabilities on the Group’s balance sheet are amounts recognised in respect of deferred revenue amounting to $22.3 million. These
liabilities will be transferred to revenue as gas is supplied to the customer or forfeited under take or pay contracts and therefore do not
represent a cash liability to the Group.
In addition, $15.8 million in liabilities are recognised relating to the second and third years of the Macquarie Gas Sale and Prepayment
Agreement which contains a financial settlement option. Ultimately this liability will be settled by either the physical delivery of gas or from
the proceeds of gas sold to third parties for which no corresponding asset is currently recognised and therefore no net cash outflow is
expected to result.
Debt
The Group borrowed a total of $17.5 million in additional funds during the year for its investment in the GAP, of which $10 million has been
repaid from the increased cashflow during the six months following connection of the NGP. A further $10 million in debt is scheduled for
repayment by December 2019.
The consolidated debt ratio at 30 June 2019 was 0.48 (2018: 0.49). Debt ratio is defined as: Total Debt/Total Assets. Net gearing at
30 June 2019 was 40% (2018: 33%). Net gearing is calculated as: Net Debt / (Market capitalisation + Net Debt). Debt funding is supported by
long term gas sales contracts and the Group’s certified 2P reserves.
Net Working Capital
Cash decreased by $9.4 million to $17.8 million at 30 June 2019, reflecting the significant investment in the GAP and Palm Valley 13
exploration costs during the year.
Net working capital at 30 June 2019 was negative $1.5 million (2018: positive $17.2 million) after recognition of $6.0 million in current
liabilities associated with the Macquarie Gas Sale and Prepayment Agreement. These liabilities will be settled either by the physical delivery
of gas to Macquarie or where physical delivery is not requested, out of the proceeds of the sale of that gas to third parties.
Net Cashflow from Operations
Net cashflow from operations decreased from $5.2 million in 2018 to $2.5 million for 2019. Cashflow from operations includes $18.1 million
of cash outflows associated with the Group’s exploration activities, which during 2019 included the Palm Valley 13 exploration well.
Second half net cashflow from operations was $16.9 million compared to the first half cash outflow of $(14.5) million, reflecting completion
of the GAP, exploration activity and commencement of gas supplies into the NGP in January 2019.
Excluding payment for exploration activities, cashflow from production operations for 2019 was $20.6 million compared to $10.4 million
for 2018.
7
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Five Year Comparative Data
The following table and discussion is a one year (and five year) comparative analysis of the Consolidated Entity’s key financial information.
The Statement of Financial Position information is as at 30 June each year and all other data is for the years then ended.
2019
$ MILLION
2018
$ MILLION
2017
$ MILLION
2016
$ MILLION
2015
$ MILLION
Financial Data
Operating revenue
Exploration expenditure
Loss after income tax
Equity issued during year
Property, plant and equipment
Borrowings
Net Assets (Total Equity)
Net Working Capital
Operating Data
Gas Sales (TJ)
Oil Sales (barrels)
No. of employees at 30 June
Risk Management
59.36
15.80
14.53
—
123.48
(81.73)
(5.62)
(1.53)
2019
10,229
97,392
99
34.94
8.79
14.08
25.47
103.85
(78.33)
7.06
17.19
2018
4,842
105,619
89
24.79
1.90
24.73
—
106.82
(82.17)
(5.96)
0.73
2017
3,322
111,380
83
23.86
4.03
21.04
11.52
113.78
(85.70)
16.52
5.33
2016
3,230
98,635
83
10.31
7.66
27.73
5.56
58.58
(47.46)
23.15
(4.41)
2015
1,194
53,925
58
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 2019
The principal risks and uncertainties outlined in this section may materialise independently, concurrently or in combination. These risks and
uncertainties 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
fields. Our
production outcomes across our
disciplined management of opportunities and
acquisitions, together with the application of existing
technologies and
further
addresses this risk.
recovery processes,
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
8
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Context
Risk
Mitigation
Oil and Gas Reserves
of
Commercialisation
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.
Operating
Production and delivery of
hydrocarbon products to plan
are key elements of our
financial
operational
directly
performance
impact shareholder returns.
and
and
Financial
Central’s financial strength and
performance underpins our
strategy and future growth.
uncertainty.
Reservoir / field performance is subject to
subsurface
actual
performance could vary from those forecasted,
which may result in diminished production and
/ or additional development costs.
The
Our facilities are subject to hazards associated
with the production of gas and petroleum,
including major accident events such as spills
leaks which can result
and
loss of
hydrocarbon
diminished
containment,
production, additional costs, environmental
damage or harm to our people, reputation or
brand.
in a
liquidity
to meet
Insufficient
financial
commitments and fund growth opportunities
could have a material adverse effect on our
operations and financial performance.
Our reserve and resource estimates are prepared in
accordance with the guidelines set forth in the 2018
Petroleum Resources Management System (PRMS).
We proactively analyse reservoir performance and
undertake comprehensive production and economic
modelling to determine the most likely outcomes
across our fields.
We 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.
controls which
is based on a
Our operational performance
framework of
the
enable
management of these risks. We have in place asset
inspections,
integrity management processes,
maintenance procedures and performance standards
across all infrastructure to ensure 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.
Insurance coverage is determined by the availability
of commercial options and cost / benefit analysis,
considering Central’s risk management program.
We have a robust internal expenditure management
and forecasting process which is monitored against a
Board approved budget to ensure our strategy is
appropriately funded. We prioritise debt reduction
which strengthens our balance sheet and supports
the ability to access suitable additional funding
where required to support growth. We also actively
seek partnering opportunities to share risks and
assist in funding key activities on a project-by-project
basis.
9
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Context
Financial
Risk
Mitigation
Central’s 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.
revenue
represented
than 20% of
Oil
consolidated sales revenue in FY2019 and this is
expected to decrease further with a full year of post
NGP gas sales.
less
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
is
focussed on availability of supply and is not
considered to have significant potential impact
on price.
this mechanism
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.
The majority of Central’s revenue is from natural gas
sales denominated in AUD and the uncertainty with
this commodity is mitigated through long term fixed-
price gas sales agreements with
‘take-or-pay’
provisions.
Health and Safety is an area of focus for Central and
through our risk management framework we are
implementing plans that
include 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.
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 leading to an incident
may adversely impact not just the environment,
but our people, the communities in which we
operate, our reputation and our licence to
operate.
Environmental management is a very high priority for
Central. We operate under approved Field
Environmental Management Plans and have a
program of regular environmental inspections and
audits in place to ensure compliance. We also
continue to assess and develop our standards to
prevent, monitor and
impact of our
operations on the environment.
limit the
Health and Safety
Health and Safety is at the heart
of all activities and decisions at
Central.
Environment
Our environmental performance
underpins our licence to operate.
Information Technology
and
is reliant upon our
Central
systems
infrastructure
availability and reliability to
support the business operating
safely and effectively.
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).
We carry third party environmental liability insurance
in addition to well control insurance to mitigate
financial impacts should an event occur.
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.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
10
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Context
Risk
Mitigation
Human Resources
Central must have the right
capability and capacity, within
our personnel to perform in line
with expectations to support
our business.
Failure to establish and develop sufficient
capability to support our operations and
advance our organisational culture 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.
Regulatory Compliance /
Change
Our business activities are
subject to extensive regulation
and government policy. Our
business
is
underpinned by our licence to
operate.
performance
Climate Change
Central faces risks associated
with climate change including
fluctuations in product demand,
carbon pricing and increased
stakeholder expectations.
Geographic Concentration
Central faces risks associated
with the concentration of its
production assets.
Access to Infrastructure
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.
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
in which
and stakeholders within
we operate.
jurisdictions
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 our hydrocarbons.
We are focused on ensuring our portfolio is robust in
a potentially carbon constrained market and engage
proactively with key
industry and government
stakeholders. We also note that demand for natural
gas could increase as part of a clean energy future
compared to other energy sources.
Central’s revenue is derived from oil and gas
production
leaving
Central exposed to downsides associated with
weather conditions and infrastructure failure.
in the Amadeus Basin
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 diversify our business.
We are also investigating other new ventures outside
of the Amadeus Basin.
Our financial performance and
growth strategy are dependent
on access to third party owned
infrastructure.
Negative impacts to revenue as a result of
increased
infrastructure
tariffs or
third party owned
restricted access
infrastructure.
failure,
to
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.
11
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Context
Community
Risk
Mitigation
Our proactive engagement and
support of local and indigenous
communities is at the core of
how we operate.
Our interactions with, and decisions involving
landholders, traditional owners, suppliers and
the community fails to attract and maintain the
in
continued support of the communities
which we operate, impacting our social licence
to operate.
We work in conjunction with our key stakeholders
and have established programs to support and assist
the communities in which we operate through
procurement,
donations,
training and providing ongoing local employment
opportunities.
sponsorships,
local
Business Strategy
Over the past five years, Central has successfully implemented its strategy to gain critical mass in conventional gas production and
uncontracted gas reserves in order to take advantage of a tightening domestic gas market. This strategy encompassed:
•
•
•
•
the acquisition of the Palm Valley and Dingo gas fields from Magellan in April 2014;
the acquisition of 50% of Mereenie from Santos (including becoming Operator for the Joint Venture) in September 2015;
the substantial upgrade of the Mereenie and Palm Valley gas fields’ surface facilities to maximise sales capacity and accelerate
delivery of existing reserves; and
the commencement of gas supply to the critically short east coast market with the commencement of the operation of the NGP
operations on 3 January 2019.
This has transformed Central into a substantial onshore domestic gas producer, with 10.2 PJ of gas sales during the 2019 financial year, and
7.3PJ of gas sales since the connection of the NGP in the 2nd half of 2019.
Central also undertook an appraisal drilling programme to increase uncontracted 2P reserves. Whilst the results of the first appraisal well
(WM 26 at Mereenie) were disappointing, the PV 13 appraisal well at Palm Valley encountered commercial flow rates and is supplying sales
gas after being tied in to existing production facilities on 17 May 2019. Central had 144.7 PJ of 2P gas reserves across all producing fields as
at 30 June 2019.
With the Mereenie, Palm Valley and Dingo fields under Central’s operatorship, Central is now in a unique position to benefit from the
additional market access provided by the NGP. This strategy was driven by the clear fundamentals of leveraging a connection of a domestic
gas shortfall on the east coast with the underexplored onshore gas potential in the Northern Territory. Central’s strategy of acquiring
previously market-limited gas assets and uncontracted gas reserves, in advance of the connection of the NGP, has positioned the Company
as a direct beneficiary of the subsequent market expansion.
The acquisition of Palm Valley, Dingo and Mereenie were underpinned by existing long-term gas sale agreements (GSAs) which incorporate
fixed prices with CPI escalation. More recent GSAs have been structured on a similar fixed price basis. This provides a solid revenue stream
to support Central’s operating activities and debt financing arrangements. These fixed price contracts are not affected by oil price or currency
movements, shielding these commitments from volatility in international oil or LNG markets. Any future reserve additions and gas sales
agreements are expected to result in value accretion to those assets, as will potential improved debt financing terms as Central’s operations
mature with greater gas sales to the newly connected east coast gas market.
Central is currently well advanced in marketing gas which is becoming available for the period commencing January 2020 as legacy contracts
are completed. The market, newly connected to the east coast by the NGP, is demonstrating strong demand and pricing.
Exploration and appraisal
Central’s exploration footprint represents a rare opportunity in Australia, covering largely under-explored hydrocarbon-bearing basins with
enormous potential. The strong cash flow generated from the producing oil and gas fields provides a firm base from which Central can enter
the next phase of its growth strategy and focus capital on value accretive exploration and appraisal activities.
In the past year, the exploration program has delivered promising results in the Amadeus Basin in Central Australia through the Dukas-1 well
and substantial certified 2C coal seam gas resources at the Range gas project in Queensland’s Surat Basin.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
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DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Dukas-1 exploration well
As part of testing Central’s very substantial portfolio of significant high-risk opportunities that have the potential to become substantial gas
fields - in this case pre-salt plays in the Amadeus basin, Central’s joint venture (JV) partner Santos drilled the Dukas-1 exploration well
commencing in April 2019. Santos is operating the Dukas-1 well drilling programme, carrying 100% of the cost of the well to earn a 70% share
of EP112.
In August 2019 at 3,700m, just above the currently prognosed primary target, the well encountered extremely high pressures in excess of
the capabilities of the drill rig and surface equipment. Drilling was suspended, logging was completed, and the rig was released from site.
Although the target formations were not reached at this time, there are positive indicators for a working petroleum system with an efficient
regional seal. The testing and drilling data will be analysed before a forward plan is determined.
These are encouraging results and Central looks forward to working with Santos to further develop this opportunity.
Range gas project
In addition to leveraging its Northern Territory gas assets and taking advantage of the recent connection to the east coast gas market, Central
secured highly sought-after exploration acreage in the heart of the intensively developed Queensland coal seam gas production area, known
as the Walloons Fairway, in a creatively crafted bid with Incitec Pivot Limited (IPL). Central was granted ATP 2031 on 29 August 2018 as
successful tenderer in a Queensland Government tender process. The tender committed a 4-year programme, comprising nine wells and at
least one production test pilot. IPL joined Central as a 50/50 JV partner and committed to contributing up to $20 million of the exploration
and appraisal costs.
A four well exploration programme was completed in August 2019 with exciting results showing net coal thickness on prognosis and
permeability in line with, or better than, expectations throughout the permit. These results underpinned a similarly exciting maiden 2C
resource which exceeded high-side expectations at 270PJ (135PJ net to Central) certified by Netherland, Sewell & Associates. These 2C
resources were certified after year end and are not included in the reported reserves and resources at 30 June set out on page 22 of
this report.
The Joint Venture is now selecting a location for a production pilot to demonstrate gas flows to surface and Central looks forward to
expediting development, targeting a final investment decision in early 2021 and first gas in late 2022.
New exploration strategy
Central is finalising a near-term exploration programme for prospects that can be advanced in one to two years without significant additional
analysis. Priority will be given to lower risk prospects which are 100% held by Central, have no regulatory barriers, do not require additional
seismic work, and are in proven plays and close to existing facilities and infrastructure.
Detailed play-based exploration analysis is being carried out for medium to long-term prospects spread over the five complex working
petroleum systems which lie within Central’s 188,000km2 of exploration permits. This analysis will form the basis for the medium to
long-term exploration strategy. We anticipate this important analysis to be completed this year with an exploration strategy for the medium
to long term targets to be finalised in early CY2020.
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CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Operations and Activities
Granted Petroleum Permits, Licences and Application Interests
Sales Volumes (Central Petroleum’s Share)
Product
Gas
Crude and Condensate
Producing assets
Unit
FY 2018/19
FY 2017/18
PJ
bbls
10.2
4.8
97,392
105,619
Mereenie Oil and Gas Field (OL4 and OL5)
Northern Territory
(CTP—50% Interest (Operator), Macquarie Mereenie Pty Ltd—50% Interest)
Sales volumes (CTP share)
Unit
FY 2018/19
FY 2017/18
Reserves (CTP share)
Unit
1P
2P
2C
Gas
Crude and Condensate
PJ
bbl
7.1
4.0
Gas
PJ
71.19
81.55
91.20
97,392
105,619
Oil
MMbbl
0.68
0.87
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. During the year the Northern Gas Pipeline commenced operations, enabling Mereenie
gas to access the east coast market for the first time.
The Mereenie hydrocarbon accumulation is contained in an elongated 4-way dip anticline that has a length of 40km and width of more than
5km. 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 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.
During the year, the Mereenie Expansion Project (part of the GAP) was successfully delivered on schedule and on budget. This was an
excellent outcome given that the project was delivered on an accelerated schedule only six months after major equipment was procured.
Due to the expansion, the facilities can now deliver firm plant capacity of 44 TJ/d.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
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DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
New equipment installed as part of the Mereenie Facility Upgrade
The focus at Mereenie has now shifted to field production and plateau maintenance. To offset ongoing natural field decline, a series of minor
projects are being identified for implementation over the coming year. In particular, this includes a series of turnarounds involving the
conversion of injector wells into production wells. In addition, planning has commenced for a significant recompletion campaign to access
gas currently behind pipe. This campaign is expected to be executed in mid-2020 after the various approvals have been obtained. This
provides an opportunity to further appraise the Stairway via a series of targeted recompletions which will aim to demonstrate commercial
gas flows from the Stairway formation. It is anticipated that new development wells will be required to maintain production levels, with the
number and timing to be driven by field performance.
Palm Valley Gas Field (OL3)
Northern Territory
(CTP—100% Interest)
Sales volumes (CTP share)
Unit
FY 2018/19
FY 2017/18
Reserves (CTP share)
Unit
1P
2P
2C
Gas
PJ
1.9
-
Gas
PJ
18.49
25.83
13.58
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 29km in length and 14km in width.
During the year, the field was successfully restarted in order to deliver gas into the broader gas market available via the NGP connection and
now has four producing wells. Unfortunately, field performance was less than anticipated and this resulted in a downwards adjustment to
reserves during the year. However, the Palm Valley 13 well was successfully drilled and brought on-line which has enabled the field to deliver
up to 13 TJ/d of sales gas. A gradual decline in production is anticipated from the Palm Valley field in coming years to circa 5 – 7 TJ/d.
The focus has now shifted to increasing field production capacity through the installation of either additional compressors or via reconfiguring
the existing compressors. If successful, this project would help mitigate some of the natural field decline.
Palm Valley appraisal
Planning is continuing for additional appraisal and production wells in the Palm Valley field to target previously undrilled areas. If successful,
this could see an upgrade of the 2C resources to 2P and the introduction of additional new production capacity.
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CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Palm Valley-13 well during commissioning
Dingo Gas Field (L7) and Dingo Pipeline (PL30)
Northern Territory
(CTP—100% Interest)
Sales volumes (CTP share)
Unit
FY 2018/19
FY 2017/18
Reserves (CTP share) Unit
1P
2P
Gas
PJ
0.9
0.8
Gas
PJ
30.49
37.32
2C
-
Gas was discovered at the Dingo field in 1985 in the Neoproterozoic lower Arumbera Sandstone. The structure is 11km by 5.6km, and the
productive reservoir is at a depth of approximately 3,000 metres subsurface.
The Dingo Gas Field development, completed in April 2015, comprised the construction of wellhead facilities, gathering pipelines, gas
conditioning facilities, a 50km gas pipeline to Brewer Estate in Alice Springs and custody transfer metering facilities. It was designed to service
a gas sales contract with Territory Generation.
During the year, a water bath heater was installed to improve production stability and reduce methanol consumption. The field continued
to supply the Owen Springs Power Station from two producing wells. Gas sales to Owen Springs are expected to increase when the
Northern Territory Government decommissions the existing Ron Goodin power station.
Surprise Oil Field (L6)
Northern Territory
(CTP—100% Interest)
In February 2014, Central was granted the Petroleum Production Licence (L6) for the Surprise Oil Field Development. Initial production and
storage facilities were installed to allow production to commence in March 2014, and additional storage tanks and ancillary equipment were
completed in 2015. The Surprise West well produced approximately 88,650 barrels of oil between 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. The potential for a restart is being reviewed alongside a broader review of exploration and appraisal opportunities
in the portfolio. Environmental and reservoir monitoring continued throughout the year.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
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DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Range gas project (ATP 2031)
Surat Basin, Queensland
(CTP—50% Interest, Incitec Pivot Queensland Gas Ltd (IPL) – 50%)
Reserves (CTP share)
Unit
Gas
PJ
1P
-
2P
-
2C
135
The Company’s wholly-owned subsidiary Central Petroleum Eastern Pty Ltd was formally granted the Authority to Prospect (ATP) 2031 in
Queensland’s gas-rich Surat Basin on 28 August 2018 for a term of 12 years. The exploration and appraisal program is being undertaken
through a 50:50 joint venture arrangement with IPL. Under the arrangement in place, IPL will free carry the Company by contributing up to
$20 million of the exploration programme costs for the initial exploration period. Gas production from this permit is to be dedicated to the
east coast domestic gas market.
During the year, the parties commenced exploration drilling with the spudding of the Range 4 exploration well, only 10 months after the
grant of the permit. The exploration programme consisted of four wells, with each well being drilled to gather geological data including coal
depth, thickness and permeability. To minimise costs, the wells were drilled as slimholes and are planned to be plugged and abandoned.
The block is situated in the Surat Basin, a geological province that has been developed extensively over the last decade. No coal seam gas
wells were previously drilled in the permit, but there are a number of coal seam gas wells in adjacent blocks. The permit area covers 77km2
and is located approximately 28km North-West of the town of Miles which is estimated to be half way between the Wooleebee Creek and
Bellevue coal seam gas developments.
Location of Project Range (ATP 2031) in relation to other coal seam gas projects in the Surat Basin
The four well exploration programme was completed in August 2019, encountering average net coal thickness of 30m and permeability in
line with, or better than expected, recorded in all wells, including in the deeper Taroom coal seams. The results enabled reserves and
resources certifier, Netherland Sewell & Associates to certify 270 PJs (100% JV) of 2C Resources in August 2019.
The certified 2C resources significantly exceeded expectations, and the results indicate that the area is suited to low-cost un-fracked vertical
well development. Given the production history of gas fields in the surrounding area, the Company has a high degree of confidence that the
2C resources can be converted into 2P reserves to support a final investment decision in 2021.
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CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Map of ATP 2031 and the four Project Range exploration wells
Exploration assets
Exploration Portfolio Review and High-grade Seriatim
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 188,767 km2 (76,318 km2 granted and 112,450 km2
under application). The Amadeus Basin has, to date, been a focus for the majority of Central’s exploration activity, with ~170,000km2 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 by any standard underexplored with only a total of 39 exploration wells and
~14,500km 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 of this year, Central’s Northern Territory exploration assets now
have a clear pathway to an attractive east coast gas market. Recognising this new market dynamic, Central has significantly augmented its
exploration capabilities, including a new GM Exploration (April 2019) and a new experienced Reservoir Engineer (March 2019).
With augmentation of exploration capabilities complete, the Company initiated a full exploration portfolio review and update, incorporating
historical and recently acquired technical data in order to generate a systematic and consistent play-based approach to drive new exploration
strategies. Play-based exploration methodologies, incorporating the integration of seismic data, log and palynological data, structural
analysis, geochemistry, 3D basin modelling, consistent well failure analysis and gross depositional environment maps will allow the systematic
creation of common risk segment maps at all play levels. This information will be actively utilised in the future for permit management,
business development, work program creation and portfolio management.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
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DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Initial indications from this portfolio review show that the Amadeus Basin is one of the few remaining large under-explored on-shore working
hydrocarbon systems in Australia. A total of 115 potential targets (65 gas and 50 oil) have been identified at this point within Central’s permits
and applications in the Amadeus Basin.
With the initial phase of this portfolio review now nearing completion, the Company is constructing a high-grade seriatim and exploration
strategy for short, medium and longer-term maturation of leads and prospects. This is fundamental to the future growth of the Company.
Ooraminna Field (RL3 and RL4)
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 within the Pioneer Formation. Structural mapping
has been updated following the reprocessing of the seismic data and outcrop mapping. A decision on drilling the Ooraminna commitment
well will be made upon completion of the exploration portfolio review and finalisation of a near-term exploration plan.
Tenure Update
Grant of renewal for both retention licences were received from the Northern Territory Department of Primary Industry and Resources
(“DPIR”) on 9 August 2018 with a suspension of Year 1 approved on 3 April 2019. Technical work continues within the leases.
ATP909, ATP911 and ATP912
Southern Georgina Basin, Queensland
(CTP—100% interest)
Central received approval for Project Status and applied to renew the permits with the Queensland Department of Natural Resources, Mines
and Energy. The Permit renewals have subsequently been granted. Central is currently conducting Year 1 permit obligations of geology and
geophysical studies focusing on the Ethabuka structure. Ethabuka-1 was drilled in 1973 and tested gas at ~0.2 mmscfd from the Coolibah
Formation, the well was abandoned prematurely due to mechanical difficulties and weather. As such, the large Ethabuka anticline remains
to be fully tested at multiple levels. Work also continues on the development of a large hydrothermal dolomite play in the blocks.
Dukas-1 (EP112)
Southern Amadeus Basin, Northern Territory
(CTP – 30% interest, Santos earning 70%)
The Dukas-1 well was selected for drilling by the Joint Venture for the EP112 3rd (and final) farm-out completion phase. Santos is carrying
100% of the cost of this well and will earn a 70% interest in EP112 as a result. Dukas-1 is 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.
Dukas-1 is located approximately 175km south west of Alice Springs and the prospect has multi-TCF gas potential.
The Dukas gas prospect is a large structure and, given the potential size, success at Dukas would be company changing. In addition, several
other large ‘lookalike” sub-salt closures have been identified from interpretation of seismic acquired in the Southern Amadeus basin between
2016 and 2018. 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 spudded on the 16th April 2019 with a proposed total depth of 3,850m. The air-drilling assembly became stuck while drilling and
the well was subsequently side-tracked on the 16th May 2019. Drilling continued to 2,604m into the Gillen Formation where the 10 ¾”
surface casing was set. Drilling then resumed. As at the 30th June the well was at a depth of 3,391m.
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CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Location map of Dukas-1 and EP112
In August 2019, the well encountered formation pressure much higher than expected at a depth of 3,704m. The existence of highly-pressured
hydrocarbon-bearing gas close to the target formation provides strong evidence of a working petroleum system with an effective seal,
increasing the chance of a material gas resource at Dukas. The high pressures encountered were in excess of rig capacity and the well was
suspended after wireline logs were run, sidewall cores obtained, and vertical seismic profiling conducted. The data acquired will be analysed
and a forward plan will be developed. It is likely that equipment capable of safely drilling in the higher pressure environment will be required.
Southern Amadeus Basin, Northern Territory
Various Exploration Permits (see table on page 102)
Santos Stage 3 Farm out
The joint venture’s 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 in the Dingo and Ooraminna fields, respectively.
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. Santos has also requested an additional
five-month extension on the Stage 3 end date to 3 November 2019 to which Central has agreed.
Southern Amadeus Area
EP 82 (excluding EP 82 Sub-Blocks) **
EP 105**
EP 106 * & **
EP 112
EP 125 **
EP 115 (North Mereenie Block) **
Total Central Participating Interest after completion of Stage 3
Farmout to Santos
60%
60%
60%
30%
30%
60%
*
Santos (as Operator) has continued the process of an application with the NT Department of Primary Industry and Resources for consent to surrender Exploration
Permit 106.
** Santos’ right to earn and retain participating interests in the permit is subject to satisfying various obligations in their farmout agreement with Central.
The participating interests as stated assume such obligations will be met or otherwise may be subject to change.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
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DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Amadeus Basin (includes EP115 North Mereenie Block), Northern Territory
Exploration objectives have recently been prioritised to determine Central’s exploration strategy with a play-based approach. The block has
proven oil at the Larapintine system level (Pacoota Formation - Surprise Oil Field), and also contains a number of significant gravity highs
which provide potential large gas and associated Helium pre-salt targets at both the Heavitree Formation and fractured Basement levels.
A number of potentially large leads with oil potential have been identified in the vicinity of the Surprise oil field and work continues to
progress these to potentially drillable status.
Central began initial planning for the Year 3 permit commitment of 500km of seismic acquisition in EP115. The final layout has yet to be
agreed on, however the targets will include leads at the Ordovician (Stairway and Pacoota Sandstone), Arumbera, Pioneer, Areyonga and
Heavitree/ basement horizons. The data gathered in the Dukas-1 well is likely to influence the location of the upcoming seismic program
which is due to be acquired before December 2019. Therefore, an application for permit suspension is in progress to facilitate a more
informed seismic program whilst still meeting schedules necessary to keep the permit in good standing.
The Company continues to interpret in these permits, seeking to identify a variety of exploration play types and targets which could be
prospective for hydrocarbons and/or helium.
Exploration Application Areas, Northern Territory
Amadeus, Pedirka and Wiso Basins — Various Areas (see table on page 102)
The Company continued to evaluate a number of these areas and has been working to gain Native Title/ALRA 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 a preliminary seismic programme that
targets identified structural trends and leads with the aim of defining areas for follow up infill seismic has been designed.
In the Wiso Basin, a gravity survey was conducted by Geoscience Australia and 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 which will help with the planning of a proposed seismic acquisition which
will form part of the first phase of exploration once tenure is granted.
21
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
RESERVES & RESOURCES INFORMATION
Net proved (“1P”) gas reserves were 120.2 PJ and net proved (“1P”) oil reserves were 0.68 MMbbl at 30 June 2019. 1P gas reserves decreased
by 13.61 PJ through production and an adjustment at Palm Valley while 1P oil reserves decreased 0.10 MMbbl, through continued production.
Net proved plus probable (“2P”) gas reserves were 144.69 PJ and net proved plus probable (“2P”) oil reserves were 0.87 MMbbl at
30 June 2019.
Reserves and contingent resources for Mereenie and Dingo are based on volumes provided by independent expert Netherland, Sewell &
Associates Inc (“NSAI”) for the respective Petroleum Resources Management System compliant categories dated 30 June 2018. Reserves and
contingent resources for Palm Valley, are based on an internal assessment of recoverable volumes reported externally on 12 June 2019.
AGGREGATE RESERVES (Central Petroleum Share)
Unit
30/06/2018
Production for the period
01/07/2018 - 30/06/2019
Adjustments for the period
01/07/2018 - 30/06/2019
30/06/2019
Oil
Proved reserves
MMbbl
Proved plus probable reserves MMbbl
MMbbl
Contingent Resources 2C
Gas
Proved reserves
Proved plus probable reserves
Contingent Resources 2C
PJ
PJ
PJ
0.78
0.97
0.10
133.79
168.73
91.20
RESERVES PER ENTITY (Central Petroleum Share)
(0.10)
(0.10)
-
(9.82)
(9.82)
-
-
-
-
(3.80)
(14.22)
13.58
0.68
0.87
0.10
120.18
144.69
104.78
Unit
30/06/2018
Production for the period
01/07/2018 - 30/06/2019
Adjustments for the period
01/07/2018 - 30/06/2019
30/06/2019
Mereenie, oil
MMbbl
Proved reserves
Proved plus probable reserves MMbbl
MMbbl
Contingent Resources 2C
Mereenie, gas
Proved reserves
Proved plus probable reserves
Contingent Resources 2C
Palm Valley
Proved reserves
Proved plus probable reserves
Contingent Resources 2C
Dingo
Proved reserves
Proved plus probable reserves
Contingent Resources 2C
PJ
PJ
PJ
PJ
PJ
PJ
PJ
PJ
PJ
0.78
0.97
0.10
78.20
88.55
91.20
24.24
42.00
-
31.35
38.18
-
Note: Estimates may not arithmetically balance due to rounding
(0.10)
(0.10)
-
(7.01)
(7.01)
-
(1.95)
(1.95)
-
(0.86)
(0.86)
-
-
-
-
-
-
-
(3.80)
(14.22)
13.58
-
-
-
0.68
0.87
0.10
71.19
81.55
91.20
18.49
25.83
13.58
30.49
37.32
-
QUALIFIED PETROLEUM RESERVES AND RESOURCES EVALUATOR
STATEMENT
The information contained in this report regarding the Central Petroleum reserves and contingent resources 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.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
22
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
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 2019:
•
•
•
•
•
•
•
The Gas Acceleration Programme was completed in time for NGP connection;
The NGP was commissioned and commenced 3 January 2019, connecting the Northern Territory to east coast gas markets;
Gas deliveries under the Incitec Pivot GSA commenced in January 2019, representing a significant increase in gas sales;
The Palm Valley field was restarted, albeit at rates below expectations leading to a reduction of 14.2PJ of 2P reserves;
Palm Valley 13 well successfully drilled and tied into production;
Commenced drilling the Dukas 1 exploration well targeting material gas resources; and
Granted exploration ATP 2031 in Queensland’s gas-rich Surat Basin and commenced a four well exploration program, funded by a
joint venture partner.
There were no other significant events that will have a forward impact on the state of affairs of the group.
EVENTS SINCE THE END OF THE FINANCIAL YEAR
The Queensland and Texas court proceedings with Geoscience Resource Recovery, LLC (GRR) have settled. The parties filed the relevant
paperwork with the Queensland and Texas courts to finalise ending the legal proceedings. The Group has included a provision for the
settlement of this matter in the financial statements.
The Dukas exploration well in EP112 (100% free carry by Santos) was suspended after encountering much higher than predicted formation
pressures. A forward plan is to be developed over the coming months.
The four well exploration programme in ATP 2031 concluded with encouraging results. Netherland, Sewell & Associates has independently
certified 2C contingent resources of 270PJs (100% JV) of Walloons coal seam gas.
INFORMATION ON DIRECTORS
Mr Leon Devaney, BSc, MBA
Managing Director and Chief Executive Officer
Mr Devaney has 19 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 21 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.
23
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Mr Stuart Baker, BE(Elec), MBA, AICD
Independent Non-executive Director
Mr Baker was appointed as a Director on 7 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.
Dr Julian Fowles, PhD, BSc (Hons), GDipAFI, GAICD
Independent Non-executive Director
Dr Fowles was appointed as a Director on 28 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.
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 7 fold, through acquisitions and organic growth, from a loss making company to a highly profitable conglomerate with $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, capital raising and management consulting services.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
24
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Ms Katherine Hirschfeld AM, BE(Chem) UQ, HonFIEAust, FTSE, FIChemE, CEng, FAICD
Independent Non-executive Director
Ms Hirschfeld was appointed as a Director on 7 December 2018 and is a highly regarded non-executive director, having served on company
boards listed on the ASX, NZX and NYSE, as well as government and private company boards. She is currently the Chair of Powerlink, Senator
at the University of Queensland 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.
COMPANY SECRETARIES
Mr Daniel C M 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.
Mr Joseph P Morfea, FAIM, GAICD
Mr Morfea has over 40 years of experience in the resource industry having held key financial positions with both Australian and international
based companies. He was previously the chief financial officer of Magellan Petroleum Australia Pty Ltd, a wholly owned subsidiary of Denver
based Magellan Petroleum Corporation and has also held board and advisory committee positions. Prior to Magellan, Mr Morfea worked for
Santos Limited and Thiess Dampier Mitsui Coal Pty Ltd.
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
Full Meeting of
Directors
Audit Committee
Risk Committee
Remuneration &
Nominations
Committee
Community
Affairs
Committee
Eligible1 Attended
Eligible1 Attended2 Eligible1 Attended2 Eligible1 Attended2 Eligible1 Attended2
Mr Stuart Baker3
Mr Richard Cottee4
Mr Leon Devaney5
Mr Wrixon Gasteen
Ms Katherine Hirschfeld AM3
Mr Martin Kriewaldt
Mr Peter Moore6
Dr Sarah Ryan6
Mr Timothy Woodall7
4
14
4
18
4
18
11
11
9
4
—
4
18
4
17
11
11
9
1
—
—
5
1
2
—
3
2
2
—
2
5
2
5
3
3
2
1
—
—
3
1
3
1
1
1
2
—
2
3
2
3
1
1
1
1
—
—
4
1
4
2
2
1
2
—
2
5
2
5
2
2
1
2
—
—
2
2
—
—
—
2
—
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
3
4
5
6
7
The number of meetings attended includes those attended by invitation.
Stuart Baker and Katherine Hirschfeld were appointed 7 December 2018.
Richard Cottee resigned as Director 5 February 2019.
Leon Devaney was appointed as a Director 14 November 2018.
Peter Moore and Sarah Ryan resigned 13 November 2018.
Timothy Woodall resigned 29 September 2018.
25
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
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.
SHARES UNDER OPTION
(a) Options granted during or since the end of the financial year to officers of the Company as part of their remuneration:
Name of officer
Date granted
Vesting Date
Exercise Price
Expiry Date
Ross Evans
Damian Galvin
Duncan Lockhart
Robin Polson
20 Aug 2019
20 Aug 2019
20 Aug 2019
20 Aug 2019
30 Jun 2022
30 Jun 2022
30 Jun 2022
30 Jun 2022
$0.20
$0.20
$0.20
$0.20
30 Jun 20321
30 Jun 20321
30 Jun 20321
30 Jun 20321
Number of
options granted
4,170,025
2,750,000
3,333,333
2,792,758
1 On 4 September 2019 the Directors announced their intention to change to the expiry date of these options to 30 June 2023 subject to shareholder
approval at the Annual General Meeting.
Details of share rights issued during the financial year the five most highly remunerated officers as part of their remuneration are
included in Table 3 of Section H of the remuneration report contained on page 37.
(b) Unissued ordinary shares of Central Petroleum Limited or interests under option at the date of this report are as follows:
Class
Unlisted options provided to financiers
Unlisted employee options
Unlisted employee share rights
Unlisted employee share rights
Unlisted employee share rights
Unlisted employee share rights
Unlisted employee share rights
Unlisted employee share rights
Unlisted employee share rights
Unlisted employee share rights
Issue
Price
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Exercise Price
Expiry Date
Number on issue
$0.14
$0.20
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
31 Dec 2019
30 Jun 2032
05 Jan 2021
03 Oct 2022
08 Dec 2022
23 May 2023
28 Jun 2023
22 May 2024
30 Jun 2024
13 Sep 2024
22,500,000
13,046,116
7,305
5,450,401
4,515,690
16,868
135,920
7,000,371
7,804,260
23,429
60,500,360
(c) Shares issued by Central Petroleum Limited during or since the end of the year on the exercise of options or on the exercise of
rights issued to employees under the Long Term Incentive Plan are set out below. No amounts are unpaid on any of the shares.
Class
Unlisted employee share rights
Unlisted employee share rights
Unlisted employee share rights
Unlisted employee share rights
Unlisted employee share rights
Unlisted employee share rights
Exercise Price
Share issue Date Number exercised
and issued as
shares
Nil
Nil
Nil
Nil
Nil
Nil
28 Nov 2018
07 Feb 2019
10 Apr 2019
12 Apr 2019
04 Jun 2019
18 Sep 2019
2,876,183
1,038,000
266,355
1,634,631
424,754
9,053,720
15,293,643
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
26
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
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.
STAFF AND MANAGEMENT
The Directors wish to acknowledge the contributions made by the Company’s staff and management. The skills and dedication of all of
Central’s personnel both in the field and at Head Office are greatly appreciated and valued.
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 42.
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
2019
$
8,670
35,350
44,752
88,772
8,865
8,865
97,637
2018
$
8,160
—
26,259
34,419
—
—
34,419
27
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
EXECUTIVE SUMMARY - REMUNERATION
Dear Shareholders,
Over the last few years - and in particular the last year, Central Petroleum’s Board, management and staff have been focussed on
transforming the Company into a leading supplier of oil and gas to the Northern Territory and east coast energy markets. FY19 was a year
when we have seen positive signs that the Company’s strategy is working, with a 70% increase in revenues and the certification of an
additional 270PJ of 2C gas resources at the Range gas project subsequent to year end.
Critical to this strategy has been the installation of a professional and experienced management team. We have confidence that the
re-vamped Board and management team have the skills, experience and dedication to unlock the full value of the Company’s impressive
asset portfolio.
It goes without saying that an appropriate remuneration structure is an important factor in attracting and retaining key personnel and in
aligning the management team’s interests with those of shareholders. There is nothing unusual about our remuneration structure - it is
similar to many organisations, with remuneration divided into three components – Base (including superannuation), Short Term Incentive
(STI) and Long Term Incentive (LTI).
Central engages external consultants (Guerdon Associates in both 2018 and 2019) to provide a scan of similar companies annually in respect
of the remuneration levels of the CEO and those reporting to him by comparison with the market. Industry scans of the remaining positions
are received during the year. Central’s base remuneration tends to be a little higher than some of its peers, offset by a much lower STI (it is
a maximum 10% of Base while other companies can range up to 30% and beyond).
Achievement of the Short Term Incentive depends upon achieving personal, departmental and corporate objectives over the year. The
philosophy is that the base salary pays for effort and the STI pays for outcomes above the expected performance. There is an overriding
Board discretion to modify the calculated STI outcome, and that discretion was exercised in FY18 to reduce the STI to zero for certain
employees due to disappointing outcomes.
FY19 however, has been a watershed year for the Company and our staff have been successful in achieving many of the targets (refer section
F of the following Remuneration Report), including:
•
•
being awarded the new exploration tenement ATP2031 and drilling of appraisal wells that subsequently resulted in the certification
of 270 PJ of 2C gas resources at the Range gas project; and
successful mid-year completion of the Gas Acceleration Project (GAP) that has resulted in a 70% increase in revenues in FY19.
As a result, personnel received, on average, approximately 8.1% of their maximum 10% STI this year. Some key staff also received a one-off
discretionary bonus for their efforts in completing the GAP on time and on budget. Shareholders too, have shared in the benefits of these
results, with Central’s share price breaking free of its recent price range – up approximately 50% to over 20 cents at the time of writing in
early September.
For FY20, the STI targets for management and staff will cover critical aspects of our operational and growth plans, including: exploration
programmes; reserve and resource growth; gas revenue; operating cost containment; traditional owner interaction; safety; and
environmental outcomes.
The Long Term Incentive Plan (LTIP) pegs half of its reward outcomes to Central out-performing 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.
The LTIP’s Absolute TSR performance for the three years from 1 July 2016 to 30 June 2019 achieved growth of 15.5% pa and the Relative TSR
placed Central at the 88th percentile compared to its peers, resulting in approximately 75% of rights vesting for this three year performance
period. This is a result shared with shareholders over the same three year period.
To address shareholder concerns regarding the complexity of our executive remuneration structure, Central will move key executives over
to a simplified long-term incentive scheme which better aligns key management objectives with shareholder value. The Executive Share
Option Plan will replace the LTIP for key executives for the next three years.
The contents of the following Remuneration Report are prepared in accordance with the requirements of the Corporations Act and Australian
Accounting Standards. Unfortunately, these do not always reflect the actual value of remuneration received by senior executives each year.
In the spirit of improved transparency and communication, and to assist readers of this report to understand the actual remuneration which
the senior executives have received this year, we have added a new table which we hope you will find more clearly sets out the take home
value of their remuneration. This “Realised Remuneration” table can be found at section G of the following Remuneration Report (Table 1).
Wrixon Gasteen
Remuneration and Nominations Committee Chairman
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
28
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
REMUNERATION REPORT (AUDITED)
This remuneration report for the year ended 30 June 2019 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
Directors and Key Management Personnel (KMP)
Remuneration Overview
Remuneration Policy
Remuneration Consultants
Long Term Incentive Plan (LTIP)
Short Term Incentive Plan (STIP)
Realised Remuneration
Remuneration Details
Executive Service Agreements
Non-Executive Director Fee Arrangements
Voting of shareholders at the 2018 Annual General Meeting
At the Company’s 2018 Annual General Meeting, 71% of the votes cast were against the adoption of the Remuneration Report. A number
of shareholders commented on the difficulty in understanding the remuneration of Directors and Key Management Personnel as presented
in the Remuneration Report and called for increased transparency around the attainment of performance hurdles for the variable
remuneration.
The Board has considered this feedback and has taken a number of steps to improve the understanding of this year’s Remuneration Report,
including:
•
•
•
the inclusion of an executive summary from the Chairman of the Remuneration and Nominations Committee (refer previous page);
the compilation of a simplified table of ‘Realised Remuneration’ (section G of this report); and
the provision of additional information to explain the achievement of both the Long Term Incentive Plan hurdles (section E of the
report) and the Short Term Incentive Plan targets (section F of this report).
The Board has also introduced a new Executive Share Option Plan from FY2020 to replace the Long Term Incentive Plan for certain executives
to provide a more direct and transparent link between executive remuneration and shareholder value.
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
Former Directors:
Mr Richard Cottee
Non-executive Director (appointed 7 December 2018)
Managing Director (appointed 14 November 2018) and Chief Executive Officer (from 21 February
2019, acting since July 2018)
Non-executive Director (appointed 28 June 2019)
Non-executive Chairman (appointed as Chairman 2 September 2019)
Non-executive Director (appointed 7 December 2018)
Managing Director and CEO (resigned as Director 5 February 2019)
Mr Martin Kriewaldt
Non-executive Chairman (resigned 2 September 2019)
Dr Peter Moore
Dr Sarah Ryan
Non-executive Director (resigned 13 November 2018)
Non-executive Director (resigned 13 November 2018)
Mr Timothy Woodall
Non-executive Director (resigned 29 September 2018)
29
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Remuneration Report (Continued)
Other Key Management Personnel
Mr Ross Evans
Chief Operations Officer
Mr Damian Galvin
Chief Financial Officer (commenced 5 August 2019)
Mr Michael Herrington
President - Operations and Chief Development Officer (to 29 January 2019)
Mr Duncan Lockhart
General Manager Exploration (commenced 8 April 2019)
Mr Robin Polson
Mr Daniel White
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.
Financial Year 2019, summary of fixed and variable remuneration outcomes
Inflation Salary average
increases of 2%
Where appropriate, a pay rise was awarded to address inflation and on account of a change in role,
responsibilities or other extenuating circumstances.
STIP
The Company’s Short Term Incentive Plan payments were made in August 2019.
LTIP Vesting
Awards vested under the Long Term Incentive Plan for the three year period ending 30 June 2019 during
fiscal year 2020.
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 the specific circumstances of Central. 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 Long Term Incentive Plan
(“LTIP”) rather than the Short Term Incentive Plan (“STIP”).
From FY2020, certain key executives will participate in an Executive Share Option Plan instead of the LTIP, as this will provide a more
transparent alignment between executive remuneration and shareholder value.
D. Remuneration Consultants
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 has appointed Guerdon Associates to provide remuneration advice to the Board and Remuneration Committee. The works
undertaken comprised the following but the reports received did not include any specific recommendations as to the elements or amounts
of Key Management Personnel remuneration:
•
•
•
Executive KMP Market Reviews;
Equity Plan design and modelling - Long Term Incentives; and
Performance measurement of Absolute TSR as per the Performance Rights based Long Term Incentive Plan (LTIP) and proposed
peer group of Companies to adopt for those future LTIP years from 1 July 2018.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
30
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Remuneration Report (Continued)
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 periods up to and ending on 30 June 2019, the remuneration of directors and executives consisted of the following key elements:
Non-executive directors:
1. Fees including statutory superannuation; and
2. No further 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 Plan (Performance Rights or Options schemes, measured over a 3 year period); and
4. There are no guaranteed base pay increases included in any executive’s contract.
E. Long Term Incentive Plan (LTIP)
In its 2014 Annual Report, Central announced that from 1 July 2014 it would change its remuneration practices and, in particular, the structure
of its STIP and LTIP in line with market conditions relevant to the oil and gas exploration industry.
The LTIP is a major component of executive incentives and, in developing the LTIP, the Board of Central focused on creating strong linkages
between shareholder value as measured by shareholder returns and executive remuneration. Consequently, vesting conditions are divided
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 26 November 2014 and subsequently on 2 November 2015 and 14 November 2018, shareholders approved the Company’s share based
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 which will vest (Vesting Percentage) as determined by the performance conditions:
HURDLE
DEFINITION
Absolute TSR1 growth
(50% weighting)
Company's absolute TSR calculated as at vesting date.
This looks to align eligible employee’s rewards to
shareholder superior returns
HURDLE BANDING
VESTING
PERCENTAGE
Company’s Absolute TSR
over 3 years
Share Rights
Vesting
RESULT FOR
PLAN YEAR
VESTING
30 JUNE 2019
Below 10% pa
10% to <15% pa
15% to <20% pa
20% to <25% pa
0%
25%
50%
75%
25% pa plus
100%
31
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Remuneration Report (Continued)
HURDLE
DEFINITION
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.
RESULT FOR
PLAN YEAR
VESTING
30 JUNE 2019
HURDLE BANDING
Company’s Relative TSR
VESTING
PERCENTAGE
Share Rights
Vesting
Below 51st percentile
51st percentile
0%
50%
52nd to 75th percentile
51% to 99%
76th percentile and
above
100%
1
2
Total shareholder return (i.e. growth in share price plus dividends reinvested)
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 met for the performance period are then multiplied by the Vesting Percentage achieved for that hurdle
to determine the total number of unvested Share Rights which vest to become Share Rights on the vesting date, which may then be exercised
in accordance with the Employee Rights Plan Rules.
Subject to the vesting of unvested Share Rights on the Vesting Date, the unvested Share Rights vest at the rate of one Share Right for one
unvested Share Right.
Employees must be employed by the Company at the end of the performance period in order for the Performance Rights to vest. The
maximum number of Share Rights that may vest (subject to share price performance hurdles) 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 30 June.
If the Company is subject to a Change of Control Event, all unvested Share Rights will immediately vest at 100% to become Share Rights, with
all and any Performance Criteria being waived immediately.
Details of the LTIP Plan’s Key Terms can be viewed on the Company’s website at www.centralpetroleum.com.au.
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 may receive a LTIP percentage up to
50%, subject to shareholder approval;
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%;
c.
Eligible employees who are senior managers that are charged with 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.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
32
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Remuneration Report (Continued)
F. Short Term Incentive Plan (STIP)
From 1 July 2014, a performance based plan comprising a matrix of Corporate, Departmental and Individual Key Performance Indicators
(“KPIs”) for all eligible employees was implemented. The Company’s Board of Directors determine the maximum amount of KPIs 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. Consistent with the Directors’ focus on appreciation in shareholder value as the major form of incentive, STIP payments were
limited to a maximum of 10% of base salary for the financial year ended 30 June 2019.
Key terms and conditions
The Financial Year 2019 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.
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 Managing Director approves KPIs after consultation with the Board. These KPIs can change having regard to aligning employees with the
Company’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. If there
is a change as a result of this, employees participating in the STIP will be notified.
KPI CATEGORY
Corporate KPIs
Safety and Environment KPI’s
Departmental KPIs
Individual KPIs
PERCENT ALLOCATION OF STIP
Executive
30%
10%
40%
20%
All Other Employees
30%
10%
30%
30%
The Financial Year 2019 STIP percentage allocation is a maximum of up to 10% of the employee’s Base Salary. The maximum is contingent
upon all of the KPIs being met at 100% in the STIP. This formed the basis of the recommendation to the Board who decided the amount. This
percentage will be annually reviewed by the Board through the Remuneration and Nominations Committee. At the Board’s discretion the
financial year 2019 STIP has been paid as a combination of cash and company securities.
Corporate KPIs included:
OBJECTIVE
Qld Acreage Authority to Prospect (ATP)
issued & work programme approved by
Government & IPL and substantially
commenced
Drilling
Facilities capable of producing *
By 1st December 2018, and within
approved budget (firm supply on CTP’s
participating interest)
Budget (Original submission approved by
the Board, unless amended due to a
Board approved change of scope)
WEIGHTING
0%
50%
75%
100%
Performance outcome for FY19
10%
10%
60%
20%
* Eligibility to participate in the reward of all achieved Objectives within the Corporate KPI’s is dependent on the successful achievement of the Facilities capable of
producing.
33
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Remuneration Report (Continued)
Safety and Environment KPIs included:
OBJECTIVE
WEIGHTING
0%
50%
75%
100%
Performance outcome for FY19
Traditional Owner cultural
heritage: No breach
Safety: No Lost Time Injuries
(LTI)
Environment: No breach
regarding reportable
environmental incidents
Alice Springs local and
Indigenous employment
20%
30%
30%
20%
Summary Performance of Corporate KPI’s:
Corporate
Safety and Environment
Total
100%
(being 30% of STI)
100%
(being 10% of STI)
96 out of 100 (or 29 out of a
possible 30)
40 out of 100 (or 4 out of a
possible 10)
82.5 out of 100 (or 33 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. Individual KPIs are linked to the departmental KPIs and as such provides significant relevance
to the role that the employee is employed for in each department.
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).
Details of the remuneration of the Directors and the key management personnel of Central Petroleum Limited and the Consolidated Entity
are set out in section H of this report.
Gas Acceleration Program (GAP) – Outcomes Bonus
Separate to the STIP, at the board’s discretion - acknowledged one of the most important activities and subsequent achievements to have
occurred in the last two years. Delivered without injury, on time and on budget, the completion of the Gas Acceleration Program was an
absolute success resulting in almost tripling the Company’s gas sales. The project was completed in December 2018 – primarily due to those
staff who joined with new management just before the beginning of the financial year.
The Board awarded a discretionary bonus to the principal staff who achieved this. The reward was appropriate in the context of what was
achieved, the costs avoided and obviating the need for a significant capital raise. It was a mammoth effort from management and staff. The
Board congratulates those directly involved and to the rest of the team for making this outcome possible.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
34
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
G. Realised remuneration
Table 1 identifies the Actual Remuneration received 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 STI awarded as cash for the financial year but paid after the end of the financial year;
Any STI 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; and
The value of LTI share rights vesting in respect of the three-year period ending 30 June, valued at the year-end share price (2019:
14 cents per share, 2018: 14.5 cents per share).
The table below has been provided to assist shareholders to understand the remuneration received in respect of each financial year ending
30 June. The table is a voluntary disclosure and as such has not been prepared in accordance with the disclosure requirements of the
Accounting Standards or Corporations Act 2001. See Table 2 for Executive KMP remuneration in accordance with these requirements.
Table 1: Realised Remuneration
YEAR
TOTAL FIXED
REMUNERATION1
$
STI (CASH)
$
GAP BONUS
(CASH) 2
$
OTHER
BENEFITS3
$
STI VESTED AS
SHARES4
$
LTI VESTED AS
SHARES5
$
Total
$
Current Executive KMP – Senior Executives
Leon Devaney
Ross Evans6
Duncan Lockhart7
Robin Polson8
Daniel White
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
565,939
523,863
423,552
31,938
93,189
—
331,400
54,750
438,064
435,978
Former Executive KMP – Senior Executives
Richard Cottee9
Michael Herrington10
Total Executive KMP
2019
2018
2019
2018
2019
2018
364,220
607,540
314,380
524,846
2,530,744
2,178,915
49,162
—
20,000
—
—
—
13,433
—
16,909
—
—
—
—
—
41,600
—
30,000
—
—
—
24,400
—
—
—
—
—
—
—
99,504
—
96,000
—
5,159
5,460
3,896
—
—
—
4,293
—
5,159
5,460
10,105
16,550
4,668
6,280
33,280
33,750
—
—
20,000
—
—
—
13,433
—
16,909
12,404
—
—
—
—
50,342
12,404
150,917
61,589
—
—
—
—
—
—
148,401
60,567
—
150,510
102,906
73,152
402,224
345,818
812,777
590,912
497,448
31,938
93,189
—
386,959
54,750
625,442
514,409
374,325
774,600
421,954
604,278
3,212,094
2,570,887
1
2
3
4
5
6
7
8
9
Total Fixed Remuneration includes salaries, fees and superannuation contributions
Directors' discretionary bonus in respect of the Gas Acceleration Project
Includes car parking and other fringe benefits
Short term incentive issued as share rights and issued after year end valued at cash equivalent STI
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.
Ross Evans commenced 1 June 2018
Duncan Lockhart commenced 8 April 2019
Robin Polson commenced 1 May 2018
Richard Cottee ceased employment as CEO effective 31 January 2019
10 Michael Herrington ceased employment effective 29 January 2019
35
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Remuneration Report (Continued)
H. 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
$
STI1
$
Non-monetary
benefits1
$
Superannuation
contributions
$
Termination
Benefits
$
LSL
$
(At Risk)
Rights2
$
Total
$
Value of
Options&
Rights as
Proportion of
Remuneration
%
Non-Executive Directors
Stuart Baker3
Wrixon Gasteen
Robert Hubbard4
Katherine Hirschfeld3
Martin Kriewaldt5
Peter Moore6
Sarah Ryan5,6
Timothy Woodall7
Sub-total
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
47,139
—
113,750
93,333
—
104,710
47,139
—
167,746
59,362
53,333
83,333
55,417
52,670
20,000
38,889
504,524
432,297
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
912
—
—
—
—
—
—
—
—
—
—
—
—
—
912
Executive Directors and Other Key Management Personnel
Ross Evans9
Leon Devaney
Richard Cottee8
2019
2018
2019
2018
2019
2018
Michael Herrington10 2019
2018
2019
2018
2019
2018
2019
2018
Duncan Lockhart11
Robin Polson12
Daniel White
314,975
565,954
551,385
517,512
410,613
31,411
257,419
523,557
94,830
—
307,387
53,846
418,188
384,336
Sub-total
Total Remuneration
2019
2018
2019
2018
2,354,797
2,076,616
2,859,321
2,508,913
—
—
90,762
—
70,000
—
—
—
—
—
51,266
—
15,918
17,900
227,946
17,900
227,946
17,900
10,105
16,550
5,159
5,460
3,896
—
4,668
6,280
—
—
4,293
—
5,159
5,460
33,280
33,750
33,280
34,662
4,478
—
10,806
8,867
—
9,947
4,478
—
15,936
5,639
5,067
7,917
5,265
5,004
1,900
3,694
47,930
41,068
15,005
20,049
22,765
24,085
22,765
2,771
15,292
23,634
5,133
—
26,508
4,750
24,139
23,417
131,607
98,706
179,537
139,774
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
52,542
—
—
—
—
—
28,366
—
—
—
—
—
—
—
80,908
—
80,908
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
51,617
—
124,556
103,112
—
114,657
51,617
—
183,682
65,001
58,400
91,250
60,682
57,674
21,900
42,583
552,454
474,277
(68,772)
16,988
20,947
19,483
5,361
316
(53,199)
13,696
936
—
3,553
543
9,855
8,730
(343,827)
713,704
76,358
110,740
23,221
—
80,865
149,623
—
—
17,746
—
124,249
123,802
(81,319)
59,756
(21,388)
1,097,869
(19,972)
1,333,245
767,376
677,280
535,856
34,498
333,411
716,790
100,899
—
410,753
59,139
597,508
563,645
2,725,831
3,384,597
(81,319)
59,756
(21,388)
1,097,869
3,278,285
3,858,874
0%
—
0%
0%
0%
0%
0%
—
0%
0%
0%
0%
0%
0%
0%
0%
0%
0%
N/A
54%
10%
16%
4%
0%
24%
21%
0%
N/A
4%
0%
21%
22%
(1)%
32%
(1)%
28%
1
2
3
4
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. The STI was subsequently settled
partly in cash and partly in equity after year end.
The fair values of deferred share rights granted are valued using methodology that takes into account market and peer performance hurdles. The values 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.
Stuart Baker and Katherine Hirschfeld AM were appointed 7 December 2018.
Robert Hubbard retired 14 May 2018.
5 Martin Kriewaldt and Sarah Ryan were appointed 23 October 2017.
6
7
8
9
Peter Moore and Sarah Ryan resigned 13 November 2018.
Timothy Woodall was appointed 20 December 2017 and resigned 29 September 2018.
Richard Cottee ceased employment effective 31 January 2019.
Ross Evans commenced 1 June 2018.
10 Michael Herrington ceased employment effective 29 January 2019.
11 Duncan Lockhart commenced 8 April 2019.
12 Robin Polson commenced 1 May 2018.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
36
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Remuneration Report (Continued)
The following factors and assumptions were used in determining the fair value of rights granted to key management personnel during the
2019 year:
GRANT DATE
EXPIRY DATE
FAIR VALUE
PER RIGHT
EXERCISE PRICE
PRICE OF SHARES
AT GRANT DATE
ESTIMATED
VOLATILITY
RISK FREE
INTEREST RATE
DIVIDEND YIELD
24 Sep 2018
02 Oct 20181
22 Mar 20192
22 May 2024
Various
10 Apr 2024
$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
0.00%
0.00%
0.00%
1
2
Adjustment to number of LTIP Rights for plan year commencing 1 July 2015 – valued at the market price of the known vesting %
STIP Rights fully vested on issue – valued at market price on issue
The following factors and assumptions were used in determining the fair value of share rights granted during the 2018 year:
GRANT DATE
EXPIRY DATE
FAIR VALUE PER
RIGHT
EXERCISE PRICE
PRICE OF SHARES
AT GRANT DATE
ESTIMATED
VOLATILITY
RISK FREE
INTEREST RATE
DIVIDEND YIELD
01 Sep 2017
29 Nov 2017
27 Jun 2018
3 Oct 2022
18 Dec 2022
28 Jun 2023
$0.081
$0.055
$0.102
Nil
Nil
Nil
$0.115
$0.084
$0.150
87%
87%
87%
2.22%
2.09%
2.30%
0.00%
0.00%
0.00%
Table 3: Share Based Compensation – Share Rights Granted 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 Evans2
Michael Herrington3
Robin Polson4
Daniel White
2019
2018
2018
2019
2018
2018
2018
2019
2018
2019
2019
2018
2018
2019
2018
2019
2019
2019
2018
2018
183,540
1,835,910
18,319
75,089
754,705
26,714
135,920
778,854
—
891,413
89,187
892,835
38,222
603,491
—
804,984
83,464
73,843
736,319
31,647
02 Oct 18
29 Nov 17
29 Nov 17
02 Oct 18
01 Sep 17
29 Sep 17
27 Jun 18
24 Sep 18
—
24 Sep 18
02 Oct 18
01 Sep 17
29 Sep 17
24 Sep 18
—
24 Sep 18
22 Mar 19
02 Oct 18
01 Sep 17
29 Sep 17
$0.067
$0.055
$0.084
$0.067
$0.081
$0.097
$0.102
$0.087
—
$0.087
$0.067
$0.081
$0.097
$0.087
—
$0.087
$0.130
$0.067
$0.081
$0.097
$0.000
$0.000
$0.000
$0.000
$0.000
$0.000
$0.000
$0.000
—
$0.000
$0.000
$0.000
$0.000
$0.000
—
$0.000
$0.000
$0.000
$0.000
$0.000
09 Feb 21
18 Dec 22
18 Dec 22
05 Jan 21
03 Oct 22
22 Sep 20
28 Jun 23
22 May 24
—
22 May 24
05 Jan 21
03 Oct 22
22 Sep 20
22 May 24
—
22 May 24
10 Apr 24
05 Jan 21
03 Oct 22
22 Sep 20
1
2
Richard Cottee ceased employment effective 31 January 2019.
Ross Evans commenced 1 June 2018.
3 Michael Herrington ceased employment effective 29 January 2019.
4
Robin Polson commenced 1 May 2018
37
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Remuneration Report (Continued)
Table 4: Share Based Compensation – Share Rights Vested during the Year
Richard Cottee
Leon Devaney
Michael Herrington
Daniel White
MAXIMUM NUMBER
OF RIGHTS
ELIGIBLE FOR
VESTING
LTIP YEAR
COMMENCING
2,097,413
209,350
858,089
305,285
1,019,187
436,793
843,843
83,464
361,647
01 Jul 15
01 Jul 14
01 Jul 15
01 Jul 14
01 Jul 15
01 Jul 14
01 Jul 15
N/A
01 Jul 14
2019
2018
2019
2018
2019
2018
2019
2019
2018
STIP YEAR
COMMENCING
N/A
N/A
N/A
N/A
N/A
N/A
N/A
01 Jul 17
N/A
NUMBER OF
RIGHTS VESTED1
PROPORTION OF
LTIP RIGHTS
VESTED2
1,038,219
104,675
424,754
152,642
504,497
218,396
417,702
83,464
180,823
49.5%
50.0%
49.5%
50.0%
49.5%
50.0%
49.5%
N/A
49.6%
1
2
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
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
Table 5: Shareholdings of Key Management Personnel
HELD AT
BEGINNING
OF YEAR
HELD AT
DATE OF
APPOINTMENT
SPP & ON
MARKET
PURCHASE
RECEIVED
ON
EXERCISE
OF RIGHTS
NET
CHANGE
OTHER
HELD AT
DATE OF
DEPARTURE
HELD AT
END OF
YEAR
Non-Executive Directors
Stuart Baker1
Julian Fowles6
Wrixon Gasteen
Katherine Hirschfeld1
Robert Hubbard2
Martin Kriewaldt3
Peter Moore4
Sarah Ryan3,4
Timothy Woodall5
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
N/A
N/A
N/A
N/A
293,337
136,473
N/A
N/A
N/A
298,947
1,100,000
N/A
265,000
—
105,000
N/A
1,500,000
—
N/A
—
N/A
N/A
N/A
200,000
N/A
N/A
N/A
N/A
200,000
—
N/A
N/A
—
N/A
N/A
1,000,000
—
N/A
—
N/A
—
156,864
—
N/A
N/A
365,667
—
900,000
50,000
265,000
100,000
105,000
250,000
500,000
1
2
Stuart Baker and Katherine Hirschfeld AM were appointed Directors 7 December 2018
Robert Hubbard retired 14 May 2018
3 Martin Kriewaldt and Sarah Ryan were appointed Directors 23 October 2017
4
5
6
Sarah Ryan and Peter Moore resigned 13 November 2018
Timothy Woodall was appointed Director 20 December 2017 and resigned 29 September 2018
Dr Fowles was appointed Director 28 June 2019
—
N/A
—
N/A
—
—
—
N/A
N/A
—
—
—
—
—
—
—
—
—
—
N/A
—
N/A
—
—
—
N/A
N/A
—
—
—
—
—
—
—
—
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
664,614
N/A
N/A
315,000
N/A
205,000
—
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
N/A
105,000
1,750,000
N/A
N/A
1,500,000
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
38
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Remuneration Report (Continued)
Table 5: Shareholdings of Key Management Personnel (continued)
HELD AT
BEGINNING
OF YEAR
HELD AT
DATE OF
APPOINTMENT
SPP & ON
MARKET
PURCHASE
RECEIVED ON
EXERCISE OF
RIGHTS
NET
CHANGE
OTHER
HELD AT
DATE OF
DEPARTURE
HELD AT
END OF
YEAR
Executive Directors and Other Key Management Personnel
Richard Cottee6
Leon Devaney
Ross Evans7
Michael Herrington8
Duncan Lockhart9
Robin Polson10
Daniel White
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
889,933
571,829
629,022
210,000
—
N/A
572,564
250,000
N/A
N/A
—
N/A
628,823
288,000
5,983,679
Total KMP
2018
Richard Cottee ceased employment effective 31 January 2019
1,755,249
7
8
Ross Evans commenced 1 June 2018
N/A
N/A
N/A
N/A
N/A
—
N/A
N/A
—
N/A
—
—
N/A
N/A
200,000
—
216,929
—
266,380
—
—
—
104,168
—
N/A
—
—
—
160,000
400,000
1,200,000
3,040,008
—
(47,700)
842,233
104,675
424,754
152,642
—
—
504,497
218,396
—
N/A
—
—
501,166
180,823
1,430,417
656,536
(3,500)
—
—
—
—
—
—
—
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
N/A
(47,700)
4,189,294
(3,500)
664,614
N/A
889,933
1,053,776
629,022
—
—
N/A
572,564
—
N/A
—
—
1,129,989
628,823
3,777,102
5,983,679
9 Michael Herrington ceased employment effective 29 January 2019
10 Duncan Lockhart commenced 8 April 2019
11 Robin Polson commenced 1 May 2018
Deferred Share Holdings of Key Management Personnel
Under the Group’s Employee Rights Plan, eligible employees may receive rights to deferred 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. 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 as determined by the Board
(refer section E of this report).
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 (“VWAP”) at the start of the plan year.
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:
39
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Remuneration Report (Continued)
Table 6: Deferred Share Holdings of Key Management Personnel
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)
Executive Directors and Other Key Management Personnel
Ross Evans
Leon Devaney
Richard Cottee1
2019
2018
2019
2018
2019
2018
Michael Herrington2 2019
2018
2019
2018
2019
2018
2019
2018
Robin Polson
Daniel White
Total
6,952,766
5,307,887
2,985,158
2,373,104
—
—
3,380,501
2,886,237
—
—
2,795,985
2,389,666
16,114,410
12,956,894
183,540
1,854,229
75,089
917,339
778,854
—
980,600
931,057
603,491
—
962,291
767,966
3,583,865
4,470,591
(6,098,087)
(104,675)
(433,335)
(152,643)
—
—
(1,870,478)
(218,397)
—
—
(426,141)
(180,824)
(8,828,041)
(656,539)
—
(104,675)
(424,754)
(152,642)
—
—
(504,497)
(218,396)
—
—
(501,166)
(180,823)
(1,430,417)
(656,536)
1,038,219
N/A
N/A
N/A
N/A
N/A
1,986,126
N/A
N/A
N/A
N/A
N/A
3,024,345
—
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
1
Richard Cottee ceased employment effective 31 January 2019
2 Michael Herrington ceased employment effective 29 January 2019.
I. Executive Service Agreements
The details of service agreements of the key management personnel of the Consolidated Entity are as follows:
Leon Devaney, Managing Director & Chief Executive Officer
The term of the agreement expires 1 July 2022.
•
• Mr Devaney’s Total Fixed Remuneration is presently $612,061 per annum inclusive of compulsory superannuation contribution
requirements.
•
In order to terminate employment, a 6 month period of notice is required by either party, except in certain exceptional
circumstances (such as breach or gross misconduct) where a shorter time applies.
Ross Evans, Chief Operations Officer
The term of the agreement expires 1 December 2022.
•
• Mr Evan’s Total Fixed Remuneration is presently $500,403 per annum inclusive of compulsory superannuation contribution
requirements.
•
In order to terminate employment, a 6-month period of notice is required by either party, except in certain exceptional
circumstances (such as breach or gross misconduct) where a shorter time applies.
Duncan Lockhart, General Manager Exploration (commenced 8 April 2019)
•
•
•
The term of the agreement expires 8 July 2022.
Dr Lockhart’s Total Fixed Remuneration is presently $400,000 per annum inclusive of compulsory superannuation contribution
requirements.
In order to terminate employment, a 6 month period of notice is required by either party, except in certain exceptional
circumstances (such as breach or gross misconduct) where a shorter time applies.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
40
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2019
Remuneration Report (Continued)
Robin Polson, Chief Commercial Officer
The term of the agreement expires 1 October 2022.
•
• Mr Polson’s Total Fixed Remuneration is presently $335,131 per annum inclusive of compulsory superannuation contribution
requirements.
•
In order to terminate employment, a 6-month period of notice is required by either party, except in certain exceptional
circumstances (such as breach or gross misconduct) where a shorter time applies.
Daniel White, Group General Counsel and Company Secretary
The term of the agreement expires 30 November 2021.
•
• Mr White’s Total Fixed Remuneration is presently $444,081 per annum inclusive of compulsory superannuation contribution
requirements.
•
In order to terminate employment, a 3-month period of notice is required by either party, except in certain exceptional
circumstances (such as breach or gross misconduct) where a shorter time applies.
J. 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 2019.
BOARD FEES (PER ANNUM)
Chairman
Non-Executive Director
COMMITTEE FEES (PER ANNUM)
Audit
Community
Affairs
Remuneration &
Nominations
Risk
Chair
Member
Chair
Member
Chair
Member
Chair
Member
$130,000
$70,000
$10,000
$5,000
$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
25 September 2019
41
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
AUDITOR’S INDEPENDENCE DECLARATION
30 JUNE 2019
Auditor’s Independence Declaration
As lead auditor for the audit of Central Petroleum Limited for the year ended 30 June 2019, 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
25 September 2019
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.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
42
FINANCIAL REPORT
CONTENTS
Financial Statements
Consolidated Statement of Profit or Loss and Other Comprehensive Income .................................................. 44
Consolidated Statement of Financial Position ................................................................................................... 45
Consolidated Statement of Changes in Equity .................................................................................................. 46
Consolidated Statement of Cash Flows ............................................................................................................. 47
Notes to the Consolidated Financial Statements ................................................................................................................. 48
Directors’ Declaration .......................................................................................................................................................... 95
Independent Auditor’s Report to the Members…….……………………….………………….……….……….….…………………… .……………… 96
ASX Additional Information………………………………………………………………………………………………….………………………………….……102
Interests in Petroleum Permits and Pipeline Licences……………………………………………………………………………………………………104
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 which forms part of the Directors’ Report on pages 4 to 41. These pages are not part of these financial statements.
The financial statements were authorised for issue by the Directors on 25 September 2019. 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.
43
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND
OTHER COMPREHENSIVE INCOME
FOR THE YEAR ENDED 30 JUNE 2019
NOTE
2019
$
2018
$
Revenue from contracts with customers – sale of hydrocarbons
2
Cost of sales
Gross profit
Other income
Share based employment benefits
General and administrative expenses
Depreciation and amortisation
Employee benefits and associated costs
Exploration expenditure
Finance costs
Loss before income tax
Income tax credit
Loss for the year
59,357,758
(30,369,092)
34,939,194
(18,704,042)
28,988,666
16,235,152
384,728
(601,897)
(1,031,636)
(12,695,238)
(5,194,131)
(15,802,075)
(8,574,831)
1,055,184
(1,622,329)
(595,925)
(8,033,092)
(4,061,759)
(8,790,052)
(8,263,308)
3
32(d)
4(a)
4(a)
(14,526,414)
(14,076,129)
5
—
—
(14,526,414)
(14,076,129)
Other comprehensive loss for the year, net of tax
—
—
Total comprehensive loss for the year
(14,526,414)
(14,076,129)
Total comprehensive loss attributable to members of the parent entity
(14,526,414)
(14,076,129)
Basic and diluted loss per share (cents)
22
(2.05)
(2.13)
The accompanying notes form part of these financial statements.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 44
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
AS AT 30 JUNE 2019
NOTE
2019
$
2018
$
ASSETS
Current assets
Cash and cash equivalents
Trade and other receivables
Inventories
Other financial assets
Total current assets
Non-current assets
Property, plant and equipment
Exploration assets
Intangible assets
Other financial assets
Goodwill
Total non-current assets
Total assets
LIABILITIES
Current liabilities
Trade and other payables
Deferred revenue
Interest-bearing liabilities
Other financial liabilities
Provisions
Total current liabilities
Non-current liabilities
Deferred revenue
Interest-bearing liabilities
Other financial liabilities
Provisions
Total non-current liabilities
Total liabilities
Net assets
EQUITY
Contributed equity
Reserves
Accumulated losses
Total equity
7
8
9
13
10
11
12
13
14
15
2(b)
16
18
17
2(b)
16
18
17
17,805,869
9,060,155
2,719,526
—
27,222,845
6,631,642
3,575,480
2,333,333
29,585,550
39,763,300
123,475,413
103,853,369
8,898,767
113,365
2,770,782
3,906,270
8,898,767
156,017
2,535,915
3,906,270
139,164,597
119,350,338
168,750,147
159,113,638
6,006,532
6,752,568
10,956,896
2,025,014
5,375,799
8,113,667
7,283,068
3,727,338
38,600
3,406,515
31,116,809
22,569,188
15,559,186
70,773,157
13,823,493
43,094,230
13,678,980
74,599,221
15,362,506
25,840,435
143,250,066
129,481,142
174,366,875
152,050,330
(5,616,728)
7,063,308
19
20
21
197,776,487
197,776,487
25,310,162
(228,703,377)
23,463,784
(214,176,963)
(5,616,728)
7,063,308
The accompanying notes form part of these financial statements.
45
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEAR ENDED 30 JUNE 2019
CONTRIBUTED
EQUITY
$
RESERVES
$
ACCUMULATED
LOSSES
$
TOTAL
$
Balance at 1 July 2017
172,301,532
21,841,455
(200,100,834)
(5,957,847)
Total loss for the year
Other comprehensive loss
Total comprehensive loss for the year
Transactions with owners in their capacity
as owners
Share based payments
Share and option issues
Share issue costs
—
—
—
—
—
—
(14,076,129)
—
(14,076,129)
—
(14,076,129)
(14,076,129)
—
27,250,000
(1,775,045)
25,474,955
1,622,329
—
—
1,622,329
—
—
—
—
1,622,329
27,250,000
(1,775,045)
27,097,284
Balance at 30 June 2018
197,776,487
23,463,784
(214,176,963)
7,063,308
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
—
—
—
—
—
—
—
—
—
(14,526,414)
—
(14,526,414)
—
(14,526,414)
(14,526,414)
601,897
1,244,481
1,846,378
—
—
—
601,897
1,244,481
1,846,378
Balance at 30 June 2019
197,776,487
25,310,162
(228,703,377)
(5,616,728)
The accompanying notes form part of these financial statements.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
46
39,285,428
494,077
25,660
(5,987,298)
(5,250,936)
(23,393,701)
5,173,230
(2,999,815)
33,636
430,000
(2,367,302)
(4,903,481)
27,250,000
(1,775,044)
—
(4,000,000)
21,474,956
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED 30 JUNE 2019
NOTE
2019
$
2018
$
Cash flows from operating activities
Receipts from customers
Interest received
Other income
Interest and borrowing costs
Payments for exploration expenditure
Payments to other suppliers and employees
58,924,286
372,705
26,044
(6,452,096)
(18,106,028)
(32,299,549)
Net cash inflow from operating activities
28
2,465,362
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 outflow from investing activities
Cash flows from financing activities
Proceeds from the issue of shares and options
Payments for capital raising costs
Proceeds from borrowings and other financing arrangements
Repayment of borrowings
29
Net cash inflow from financing activities
Net (decrease)/increase in cash and cash equivalents
Cash and cash equivalents at the beginning of the financial year
(17,481,804)
—
—
2,098,466
(15,383,338)
—
—
17,500,000
(13,999,000)
3,501,000
(9,416,976)
21,744,705
27,222,845
5,478,140
Cash and cash equivalents at the end of the financial year
7
17,805,869
27,222,845
The accompanying notes form part of these financial statements.
47
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
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.
(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 incurred a net loss for the year of $14,526,414, had a net positive cash flow from operations of $2,465,362 and had an overall net
current liability position at 30 June 2019 of $1,531,259. The net current liabilities include $6,752,568 of deferred revenue which will not
crystallise into a cash outflow and a further $1,986,414 relates to a financial liability which will either be settled by the physical delivery of
gas or be satisfied from the proceeds of selling that gas under existing or future gas sales agreements (Note 4(b)). 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 overhead.
Supported by the cash assets at 30 June 2019 of $17,805,869, and expected operating cashflows, the Group forecasts that over at least the
next 12 months, it will have sufficient funds to meet its commitments and continue to pay its debts as and when they fall due. To date the
Group has been successful in funding new projects through a combination of borrowings, gas presales, farmouts and equity from new and
existing shareholders. The following matters have also been considered by the Directors in determining the appropriateness of the going
concern basis of preparation in the financial statements:
i.
The Group’s existing debt facilities are due to mature on 30 September 2020. The Group has received a number of term sheets
from potential financiers and is in the process of assessing the proposals. Management and the Board are confident new
arrangements will be in place before expiry of the current facility; and
ii.
The Company has access to a $10 million Equity Line of Credit with Long State Investment Limited (refer Note 19(f)).
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 (“IASB”).
(iii) Early Adoption of Standards
The Group has not applied any pronouncements to the annual reporting period beginning on 1 July 2018 where such application would result
in them being applied prior to them becoming mandatory.
(iv) Historical Cost Convention
These financial statements have been prepared under the historical cost convention.
(v) Critical Accounting Judgements and Key Sources of Estimate Uncertainty
In the application of the Group’s accounting policies, management is required to make judgements, estimates and assumptions regarding
carrying values of assets and liabilities that are not readily apparent from other sources. The estimates and assumptions are based on
historical experience and various other factors that are believed to be reasonable under the circumstances, the results of which form the
basis of making the judgements. Actual results may differ from these estimates. Key judgements in applying the entity’s accounting policies
are required in the following areas:
Rehabilitation
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.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 48
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(a) Basis of Preparation (continued)
(v)
Critical Accounting Judgements and Key Sources of Estimate Uncertainty (continued)
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.
Impairment of 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, legal
changes and commodity price changes. 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.
Impairment of 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 in determining expected future cash flows from operations.
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 Statement of Financial Position. Deferred tax assets, including those arising from un-recouped tax losses, 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 Statement of Financial Position and the amount of other tax losses and temporary
differences not yet recognised. In such circumstances, some or all of the carrying amounts of recognised deferred tax assets and liabilities
may require adjustment, resulting in a corresponding credit or charge to the Consolidated Statement of Comprehensive Income.
(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.
49
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(b) Principles of Consolidation (continued)
(i)
Subsidiaries (continued)
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 companies 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 statement of financial position 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 23 in a manner consistent with the internal reporting provided to the chief operating decision
maker. The chief operating decision maker, who is responsible for allocating resources and assessing performance of the operating segments,
has been identified as the Executive Management Team.
(d) Foreign Currency Translation
(i)
Functional and Presentation Currency
Items included in the financial statements of each of the Group’s entities are measured using the currency of the primary economic
environment in which the entity operates (the “functional currency”). The consolidated financial statements are presented in Australian
dollars, which is Central Petroleum Limited’s functional currency and presentation currency.
(ii) Transactions and Balances
Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions.
Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end exchange rates of
monetary assets and liabilities denominated in foreign currencies are recognised in profit or loss, except when they are deferred in equity as
qualifying cash flow hedges and qualifying net investment hedges or are attributable to part of the net investment in a foreign operation.
(e) Revenue Recognition
Revenue from contracts with customers is recognised in the income statement when or as the Group transfers control of goods or services
to a customer at the amount to which the Group expects to be entitled. If the consideration promised includes a variable amount, the Group
estimates the amount of consideration to which it will be entitled.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
50
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(e) Revenue Recognition (continued)
(i) Revenue from the sale of hydrocarbons
Revenue from the sale of hydrocarbons is recognised using the “sales method” of accounting. The sales method results in revenue being
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 outside the exploration phase
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.
(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. Non-monetary grants are recognised at a nominal amount.
(g)
Income Tax
Central Petroleum Limited and its wholly-owned Australian controlled entities have implemented the tax consolidation legislation. The head
entity is Central Petroleum Limited. As a consequence, these entities are taxed as a single entity. The Company and the other entities in the
tax-consolidated group have entered into a tax funding and a tax sharing agreement.
The Group accounts for income taxes in accordance with UIG 1052 adopting the “Separate Taxpayer within Group Approach”.
The income tax expense or revenue for the period is the tax payable on the current period’s taxable income based on the applicable income
tax rate adjusted by changes in deferred tax assets and liabilities attributable to temporary differences. The current income tax charge is
calculated on the basis of the tax laws enacted or substantially enacted at the end of the reporting period in the countries where entities in
the Group generate taxable income.
Each individual entity recognises deferred tax assets and deferred tax liabilities arising from temporary differences on the basis that the
entity is subject to tax as part of the tax-consolidated group. Deferred tax assets are recognised for deductible temporary differences and
unused tax losses only if it is probable that future taxable amounts will be available to utilise those temporary differences and losses. Each
entity assesses the recovery of its unused tax losses and tax credits only in the period in which they arise and before assumption by the head
entity, applied in the context of the group whether as a reduction of current tax of other entities in the group or as a deferred tax asset of
the head entity. The aggregate amount of losses or credits utilised or recognised as a deferred tax asset by the head entity is apportioned
on a systematic and reasonable basis.
Deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill. Deferred tax is also not accounted for if it arises
from initial recognition of an asset or liability in a transaction other than a business combination that, at the time of the transaction, affects
neither accounting nor taxable profit or loss. Deferred income tax is determined using tax rates (and laws) that have been enacted or
substantially enacted by the end of the reporting period and are expected to apply when the related deferred income tax asset is realised,
or the deferred income tax liability is settled.
51
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(g) Income Tax (continued)
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
Leases of property, plant and equipment where the Group, as lessee, has substantially all the risks and rewards of ownership are classified
as finance leases. Finance leases are capitalised at the lease's inception at the fair value of the leased property or, if lower, the present value
of the minimum lease payments. The corresponding rental obligations, net of finance charges, are included in other short-term and long-
term payables. Each lease payment is allocated between the liability and finance cost. The finance cost is charged to the 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. The property,
plant and equipment acquired under finance leases is depreciated over the asset's useful life or over the shorter of the asset's useful life and
the lease term if there is no reasonable certainty that the Group will obtain ownership at the end of the lease term.
Capitalised leased assets are depreciated over the shorter of the estimated useful life of the asset and the lease term if there is no reasonable
certainty that the Consolidated Entity will obtain ownership by the end of the lease term.
Leases in which a significant portion of the risks and rewards of ownership are not transferred to the Group as lessee are classified as
operating leases (Note 31(c)). Payments made under operating leases (net of any incentives received from the lessor) are 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 statement of financial position.
(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.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
52
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
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
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 statement of financial position. Amounts paid as performance bonds or amounts held as security for bank guarantees in
satisfaction of performance bonds are classified as other financial assets (Note 13).
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
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.
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 other land and buildings and other plant and equipment categories respectively.
Depreciation of producing assets is calculated using the units of production method 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 future subsurface costs
necessary to develop the hydrocarbon reserves included in the calculation.
(o) Property, Plant and Equipment – Other than Development and
Production Assets
All property, plant and equipment is stated at historical cost less depreciation. Historical cost includes expenditure that is directly attributable
to the acquisition of the items. Cost may also include transfers from equity of any gains or losses on qualifying cash flow hedges of foreign
currency purchases of property, plant and equipment.
53
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(o) Property, Plant and Equipment – Other than Development and Production
Assets (continued)
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 statement
of financial position 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
Buildings
Leasehold Improvements
Plant and Equipment
Motor Vehicles
Expected Useful Life
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 23).
(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.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
54
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(s) Provisions
(i) Restoration
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 estimated cost is capitalised by increasing the carrying amount of the related
exploration and evaluation assets or 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) Other Long-term Employee Benefit Obligations
The liability for long service leave which is not expected to be settled within 12-months after the end of the period in which the employees
render the related service is recognised in the provision for employee benefits and measured as the present value of expected future
payments to be made in respect of services provided by employees up to the end of the reporting period. Consideration is given to expected
future wage and salary levels, experience of employee departures and periods of service. Expected future payments are discounted using
market yields at the end of the reporting period with terms to maturity and currency that match, as closely as possible, the estimated future
cash outflows.
(iii) Share-based Payments
Share-based compensation benefits are provided to employees by Central Petroleum Limited.
55
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(t) Employee Benefits (continued)
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 statement of financial position.
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.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
56
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
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 24, has been prepared on the same basis as the
consolidated financial statements except as set out below.
(i)
Investments in Subsidiaries, Associates and Joint Venture Entities
Investments in subsidiaries, associates and joint venture entities 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 2018.
(a) AASB 15 Revenue from contracts with customers
AASB 15 establishes a comprehensive framework for determining whether, how much, and when revenue is recognised. AASB 15 establishes
a five-step model to be applied to all contracts with customers. The new standard is based on the principle that revenue is recognised when
control of a good or service transfers to a customer. The Group has adopted AASB 15 from 1 July 2018
57
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(aa) Standards, Amendments and Interpretations (continued)
(i) New and Amended Standards Adopted by the Group (continued)
The Group undertook a detailed review of its revenue contracts and concluded that there were no adjustments required to net profit or
opening retained earnings on transition. The Group has applied 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.
The Group does not currently enter into any gas swap arrangements nor is it in any “under-lift” position which may impact revenue
recognition.
(b) AASB 9 Financial Instruments
AASB 9 Financial Instruments addresses the classification, measurement and derecognition of financial assets and financial liabilities,
introduces new rules for hedge accounting and a new impairment model. The standard was mandatory for the Group from 1 July 2018.
The Group has undertaken an assessment of the changes and concluded that there is no material impact from the new classification,
measurement and derecognition rules on the Group’s financial assets and financial liabilities.
The Group does not currently enter into any hedge transactions and will not be affected by the new rules.
The new impairment model is an expected credit loss (“ECL”) model which requires recognition of an allowance for ECLs for all debt
instruments not held at fair value through profit or loss and contract assets recognised under AASB 15. As the Group’s trade receivables are
short term and relate to credit worthy customers and Joint Venture partners, the change to a forward looking ECL approach did not have a
material impact on the amounts recognised in the financial statements.
(ii) New Standards and Interpretations not yet adopted
(a) AASB 16 Leases
AASB 16 was issued in February 2016. It will result in almost all leases being recognised on the balance sheet by lessees, as the distinction
between operating and finance leases is removed. Under the new standard, an asset (the right to use the leased item) and a financial liability
to pay rentals are recognised. The only exceptions are short-term and low-value leases.
Impact
Management has reviewed all of the group’s leasing arrangements over the last year in light of the new lease accounting rules in AASB 16.
The standard will affect the accounting for the group’s operating leases. As at the reporting date, the group has non-cancellable operating
lease commitments of $1,898,431, see Note 31(c). Of these commitments, approximately $30,295 relate to short-term leases which will be
recognised on a straight-line basis as expense in profit or loss.
For the remaining lease commitments, the group expects to recognise right-of-use assets of approximately $1,475,000 on 1 July 2019, and
lease liabilities of $1,615,000 (after adjustments for prepayments and accrued lease payments recognised as at 30 June 2019). Unrecognised
deferred tax assets will amount to $42,000. Overall net assets will be approximately $140,000 lower, and net current assets will be $532,000
lower due to the presentation of a portion of the liability as a current liability.
The group expects that net profit after tax will increase by approximately $19,000 for 2020 as a result of adopting the new rules.
EBITDA/EBITDAX used to measure segment results is expected to increase by approximately $628,000, as the operating lease payments were
included in EBITDA, but the amortisation of the right-of-use assets and interest on the lease liability are excluded from this measure.
Operating cash flows will increase, and financing cash flows decrease by approximately $532,000 as repayment of the principal portion of
the lease liabilities will be classified as cash flows from financing activities.
The group does not act as a lessor.
Mandatory application date
The group will apply the standard from its mandatory adoption date of 1 July 2019. The group intends to apply the simplified transition
approach and will not restate comparative amounts for the year prior to first adoption. Right-of-use assets will be measured on transition as
if the new rules had always been applied.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
58
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
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
2019
$
2018
$
49,657,736
25,458,550
9,700,022
9,480,644
59,357,758
34,939,194
Revenue relating to contracts with Major Customers is disclosed in Note 23 – Segment Reporting
(b) Contract Liabilities
Current
Deferred Revenue – take or pay contracts1
Deferred Revenue – other gas sales contracts2
Total current contract Liabilities
Non-current
Deferred Revenue – take or pay contracts1
Deferred Revenue – other gas sales contracts2
Total non-current contract liabilities
Deferred Revenue
Revenue recognised that was included in the deferred revenue balances
at the beginning of the period
Revenue recognised during the year for gas forfeited under take or pay
contracts not in deferred revenue balances at the beginning of the period
2019
$
2018
$
2,714,334
2,714,334
4,038,234
4,568,734
6,752,568
7,283,068
15,559,186
10,381,732
—
3,297,248
15,559,186
13,678,980
3,827,748
—
46,807
90,950
1
2
Take or Pay proceeds 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
In June 2018 Macquarie Bank novated its rights and obligations under the First Contract Year of the MBL Gas Sale and Prepayment Agreement (refer Note 18), to
Incitec Pivot Limited (“IPL”) through a new Gas Sale Agreement. There was no cash settlement option under the novation. This resulted in $7,865,982 being
transferred from Other Financial Liabilities to Deferred Revenue. Revenue is recognised as gas is delivered to IPL.
59
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
3. OTHER INCOME
Interest
Sale of exploration permits
Profit on disposal of inventory and other assets
Other income
Total other income
4. EXPENSES
(a) Loss before income tax includes the following specific expenses
NOTE
Depreciation
Buildings
Producing assets
Plant and equipment
Leasehold improvements
Total depreciation
Amortisation
Software
2019
$
2018
$
360,058
—
—
24,670
525,109
280,000
224,415
25,660
384,728
1,055,184
2019
$
350,203
7,851,021
4,394,912
39,602
2018
$
350,202
3,657,662
3,950,098
33,414
12,635,738
7,991,376
59,500
41,716
Rental expense relating to operating leases – Minimum lease payments
735,845
609.396
Finance costs
Interest charge on debt facilities
Interest on other financial liabilities
Revaluation of financial liabilities
Amortisation of deferred finance costs
Accretion charge
(b)
Individually significant items
Revaluation of financial liabilities
4(b)
6,466,119
649,787
(163,786)
1,132,952
489,759
8,574,831
6,003,851
938,119
414,431
393,147
513,760
8,263,308
In 2016 the Group entered into a Gas Sale and Prepayment Agreement (“GSPA”) with Macquarie Bank Limited (“MBL”), to commence
following completion of the Northern Gas Pipeline. Under the agreement Macquarie may elect to receive a financial settlement in lieu of
taking physical delivery of gas. The financial settlement amount, if so elected, is dependent on the ex-field price received by the Group under
any new gas sales agreements from the designated production area. In June 2018 MBL novated its rights under the first year of the GSPA to
Incitec Pivot Limited (refer also Note 18). As a result, the first year obligations will be satisfied by physical delivery of gas. For subsequent
years it will be satisfied by either the physical delivery of gas or paid out of the proceeds of the sale of gas contracted under the GSA’s for
which no asset has been recognised in the accounts.
The value of the financial liability is adjusted to reflect the latest pricing and quantity assumptions of the underlying agreements, which
impact either the timing or amount of any potential financial settlement.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
60
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
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.
(a)
Income tax expense
Current tax
Deferred tax
Income tax expense
(b) Numerical reconciliation of income tax expense
and prima facie tax benefit
Loss before income tax expense
Prima facie tax benefit at 30% (2018: 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
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
2019
$
2018
$
—
—
—
—
—
—
(14,526,414)
4,357,924
(14,076,129)
4,222,839
(341,648)
(180,569)
(1,666)
(309,262)
(486,699)
1,181
3,834,041
3,428,059
(3,834,041)
(3,428,059)
—
—
—
—
—
532,514
(532,514)
—
Unutilised tax losses for which no deferred tax asset has been recognised
127,224,588
131,114,647
Potential tax benefit at 30%
38,167,376
39,334,394
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.
61
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
5.
INCOME TAX (CONTINUED)
(e) Deferred tax assets and liabilities
Deferred tax assets
Provisions and accruals
Financial liabilities
Deferred revenue
Blackhole expenditure
Borrowing costs
PRRT1
Unutilised losses
Total deferred tax assets before set-offs
Set-off of deferred tax liabilities pursuant to set-off provisions
2019
$
2018
$
14,643,493
2,384,250
609,642
569,299
38,251
—
52,621,107
70,866,042
(14,453,731)
8,875,664
2,238,662
1,187,294
848,653
51,121
244,162,165
49,740,525
307,104,084
(13,916,012)
Net deferred tax assets not recognised
56,412,311
293,188,072
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
PRRT1
Total deferred tax liabilities before set-offs
Set-off of deferred tax assets pursuant to set-off provisions
13,916,012
537,719
12,050,541
1,865,471
14,453,731
13,916,012
11,555,623
2,898,108
12,060,386
1,855,626
14,453,731
13,916,012
11,274
476,254
13,966,203
—
14,453,731
(14,453,731)
12,061
463,254
9,930,815
3,509,882
13,916,012
(13,916,012)
Net deferred tax liabilities
—
—
Movements in deferred tax liabilities
Opening balance at 1 July
Charged / (Credited) to the income statement
Closing balance at 30 June
Deferred tax liabilities to be recovered after more than 12-months
Deferred tax liabilities to be recovered within 12-months
13,916,012
537,719
12,050,541
1,865,471
14,453,731
13,916,012
14,442,457
11,274
13,903,950
12,062
14,453,731
13,916,012
1
In April 2019 The Treasury Laws Amendment (2019 Petroleum Resource Rent Tax Reforms No. 1) Bill 2019 received Royal Assent, removing onshore petroleum projects from
the scope of Petroleum Resource Rent Tax (PRRT) from 1 July 2019. The Group does not have any offshore Petroleum Projects subject to PRRT.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
62
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
5.
INCOME TAX (CONTINUED)
(f)
Other tax related matters
In July 2018 the Consolidated Entity submitted objections in respect of its income tax assessments for the income years ended 30 June 2013
to 30 June 2016 inclusive. The objections relate to Research & Development Tax offsets and the treatment of Farmout Arrangements in
respect of those years of income. At 30 June 2019 the objections were still under review by the Australian Taxation Office and the
Consolidated Entity has not recognised any potential tax benefits from the objections lodged.
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
2019
$
2018
$
199,681
43,430
243,111
8,670
35,350
44,752
88,772
8,865
8,865
173,401
—
173,401
8,160
—
26,259
34,419
—
—
Total remuneration of PwC
340,748
207,820
7. CASH AND CASH EQUIVALENTS
Cash at bank and in hand
Made up as follows:
Corporate (a)
Joint arrangements (b)
17,805,869
27,222,845
17,296,319
509,550
26,706,273
516,572
17,805,869
27,222,845
(a) $3,084,832 of this balance relates to cash held with Macquarie Bank Limited to be used for allowable purposes under the Facility
Agreement (2018: $1,782,026), 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.
Risk exposure
The Group’s exposure to interest rate risk is discussed in Note 33. The maximum exposure to credit risk at the end of the reporting period is
the carrying amount of cash and cash equivalents.
63
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
8.
TRADE AND OTHER RECEIVABLES
Current
Trade receivables
Accrued income (a)
Other receivables
Prepayments
2019
$
372,371
7,427,028
30,595
1,230,161
2018
$
1,556,150
4,121,642
57,541
896,309
9,060,155
6,631,642
(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 Financial Risk Management).
9.
INVENTORIES
Crude oil and natural gas
Spare parts and consumables
Drilling materials and supplies at cost
2019
$
107,920
1,870,295
741,311
2018
$
337,534
1,877,937
1,360,009
2,719,526
3,575,480
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
64
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
10. PROPERTY, PLANT AND EQUIPMENT
Year ended 30 June 2018
Opening net book amount
Additions
Changes to rehabilitation estimates
Disposals and write offs
Depreciation charge
Closing net book amount
At 30 June 2018
Cost
Accumulated depreciation
Net book amount
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
FREEHOLD LAND
AND BUILDINGS
PRODUCING
ASSETS
PLANT AND
EQUIPMENT
$
$
$
3,229,217
76,109,148
27,477,994
—
—
—
—
4,668,165
379,448
—
611
(19,838)
(3,983,512)
(350,202)
(3,657,662)
TOTAL
$
106,816,359
4,668,165
380,059
(19,838)
(7,991,376)
2,879,015
72,830,934
28,143,420
103,853,369
3,868,743
(989,728)
84,823,014
(11,992,080)
49,442,072
(21,298,652)
138,133,829
(34,280,460)
2,879,015
72,830,934
28,143,420
103,853,369
2,879,015
—
—
—
72,830,934
—
16,066,651
28,143,420
16,187,514
5,424
103,853,369
16,187,514
16,072,075
—
(1,807)
(1,807)
(350,203)
(7,851,021)
(4,434,514)
(12,635,738)
2,528,812
81,046,564
39,900,037
123,475,413
3,868,743
100,889,665
65,546,087
170,304,495
Accumulated depreciation
(1,339,931)
(19,843,101)
(25,646,050)
(46,829,082)
Net book amount
2,528,812
81,046,564
39,900,037
123,475,413
11. EXPLORATION ASSETS
Acquisition costs of right to explore
Movement for the year:
Balance at the beginning of the year
Balance at the end of the year
2019
$
2018
$
8,898,767
8,898,767
8,898,767
8,898,767
8,898,767
8,898,767
65
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
12.
INTANGIBLE ASSETS
SOFTWARE
At the beginning of the year
Cost
Accumulated amortisation
Net book value
Movements for the year
Opening net book amount
Additions
Disposals and write offs
Amortisation
Closing net book amount
At the end of the year
Cost
Accumulated amortisation
Net book value
13. OTHER FINANCIAL ASSETS
Current
Security deposits paid for drilling operations
Non-Current
Security bonds on exploration permits and rental properties
2019
$
2018
$
495,191
(339,174)
156,017
156,017
16,848
—
(59,500)
113,365
512,039
(398,674)
113,365
379,615
(297,458)
82,157
82,157
115,576
—
(41,716)
156,017
495,191
(339,174)
156,017
—
2,333,333
2,770,782
2,535,915
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.
14. GOODWILL
Goodwill arising from business combinations
Impairment tests for goodwill
3,906,270
3,906,270
Goodwill is monitored by management at the level of the operating segments and has been allocated to gas producing assets. 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 2P
reserves, including 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.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
66
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
14. GOODWILL (CONTINUED)
The following table sets out the key assumptions used in assessing the fair value less cost to sell of producing assets:
2019
Producing Assets
Sales volumes
Sales price (% annual growth rate)
Operating costs (% annual growth rate)
Post-tax discount rate (%)
2P Reserves
2.5%
2.5%
11.75%
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, until 2P reserves
are utilised. 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 term sheet 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.
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.
Long term 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.
15. TRADE AND OTHER PAYABLES
Current
Trade payables
Other payables
Tax related payables
Deposits held
Accruals
2019
$
2,079,473
39,658
634,167
150,000
3,103,234
6,006,532
2018
$
2,287,469
1,311
634,167
150,000
5,040,720
8,113,667
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.
67
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
16.
INTEREST BEARING LIABILITIES
(a)
Interest bearing liabilities (current)1
Debt facilities
(b)
Interest bearing liabilities (non-current)1
Debt facilities
1 Details regarding interest bearing liabilities are contained in Note 33(e).
2019
$
2018
$
10,956,896
10,956,896
3,727,338
3,727,338
70,773,157
74,599,221
70,773,157
74,599,221
17. PROVISIONS
Employee entitlements (a)
Restoration and rehabilitation (b)
Other:
Joint Venture production over-lift (c)
Other provisions (d)
2019
2018
Current Non-current
$
$
Total
$
3,529,565
529,681
763,299
38,322,469
4,292,864
38,852,150
Current Non-current
Total
$
2,883,557
522,958
$
660,179
21,639,197
$
3,543,736
22,162,155
—
1,316,553
4,008,462
—
4,008,462
1,316,553
—
—
3,541,059
—
3,541,059
—
5,375,799
43,094,230
48,470,029
3,406,515
25,840,435
29,246,950
(a)
(b)
(c)
The current provision for employee entitlements includes accrued short term incentive plans, all 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 $738,952 (2018: $778,897).
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.
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.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
68
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
17. PROVISIONS (CONTINUED)
Movements in Provisions
Movements in each class of provision during the financial year are set out below:
Employee
Entitlements
Restoration &
Rehabilitation
Joint Venture
Production Over-lift
Other
2019
$
$
$
Carrying amount at start of year
3,543,736
22,162,155
3,541,059
Change in provision charged to property, plant
and equipment
—
16,072,075
—
$
—
—
Total
$
29,246,950
16,072,075
Additional provisions charged to profit or loss
2,354,446
Unwinding of discount
Amounts used during the year
—
(1,605,318)
128,161
489,759
—
467,403
1,316,553
4,266,563
—
—
—
—
489,759
(1,605,318)
Carrying amount at end of year
4,292,864
38,852,150
4,008,462
1,316,553
48,470,029
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)
2019
$
38,600
1,986,414
2,025,014
2018
$
38,600
—
38,600
45,033
13,778,460
13,823,493
83,633
15,278,873
15,362,506
In June 2018 Macquarie Bank Limited novated its rights and obligations under the First Contract Year of the MBL Gas Sale and Prepayment
Agreement, to Incitec Pivot Limited (“IPL”). This resulted in an amount of $7,865,982 being reclassified from Other Financial Liabilities to
Deferred Revenue. The balance at 30 June 2019 and 30 June 2018 represents the remaining liabilities under the Second and Third Contract
Year where Macquarie Bank Limited has an option to receive a financial settlement in lieu of physical gas delivery.
19. CONTRIBUTED EQUITY
(a) Share capital
2019
$
2018
$
713,355,716 fully paid ordinary shares (2018: 707,115,793)
197,776,487
197,776,487
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.
69
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
19. CONTRIBUTED EQUITY (CONTINUED)
(b) Movements in ordinary share capital
Balance at start of year
Placement of shares to institutional investors on
17 August 2017 at 10 cents per share
Shares issued pursuant to the 5 for 12 Entitlement Offer
on 08 September 2017 at 10 cents per share
Capital raising costs
Shares issued under Employee Long Term Incentive Plans
2018
No. of shares No. of shares
2019
2019
$
2018
$
707,115,793
433,197,647
197,776,487
172,301,532
—
92,000,980
—
—
6,239,923
180,499,020
—
1,418,146
—
—
—
—
9,200,098
18,049,902
(1,775,045)
—
Balance at end of year
713,355,716
707,115,793
197,776,487
197,776,487
(c) Movements in Share Options
No options were exercised, and no options lapsed during the year.
The following options over unissued ordinary shares were issued during the year:
CLASS
Unlisted financing options
EXPIRY DATE
31 Dec 2019
EXERCISE
PRICE
$0.140
NUMBER OF
OPTIONS
22,500,000
(d) Unissued shares under option
At year end, options over unissued ordinary shares of the Company are as follows:
CLASS
Unlisted financing options
Unlisted financing options
EXPIRY DATE
01 Sep 2019
31 Dec 2019
EXERCISE
PRICE
NUMBER OF
OPTIONS
$0.194
$0.140
30,000,000
22,500,000
None of the options entitle holders to participate in any share issue of the Company or any other entity.
(e) Deferred share rights under the Long Term Incentive Plan
Under the Group’s Employee Rights Plan, eligible employees may receive rights to deferred 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 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 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 as determined by
the Board.
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 (“VWAP”) at the start of the plan year. The table below sets out the maximum number of deferred share entitlements outstanding
at year end, subject to performance hurdles.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
70
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
19. CONTRIBUTED EQUITY (CONTINUED)
CLASS
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Total Deferred Share Rights on issue
EXPIRY DATE
PLAN YEAR
COMMENCING
NUMBER OF
RIGHTS
05 Jan 2021
08 Dec 2022
09 Feb 2022
03 Oct 2022
03 Oct 2022
23 May 2023
28 Jun 2023
22 May 2024
1 Jul 2015
1 Jul 2016
1 Jul 2016
1 Jul 2016
1 Jul 2017
1 Jul 2017
1 Jul 2017
1 Jul 2018
7,305
9,577,506
25,324
70,000
5,431,222
16,868
135,920
7,000,371
22,264,516
6,239,923 rights were converted to shares during the year (2018: 1,418,146) and 11,088,670 rights were cancelled (2018:1,523,870). The
rights do not entitle the holders to participate in any share issue of the Company or any other entity.
(f) 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.
20. RESERVES
Share options reserve
Movements:
Balance at start of year
Share based payment costs (a)
Options issued for financing
Balance at end of year
2019
$
2018
$
25,310,162
23,463,784
23,463,784
601,897
1,244,481
21,841,455
1,622,329
—
25,310,162
23,463,784
(a)
Share based payments are provided to employees as part of the Long Term Incentive Plan. Refer to Note 32 for further details of
share based payments.
71
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
21. ACCUMULATED LOSSES
Movements in accumulated losses were as follows:
Balance at the start of year
Net loss for the year
Balance at end of year
22. LOSSES PER SHARE
(a)
Basic loss per share (cents)
(b)
Diluted loss per share (cents)
(c)
Loss used in loss per share calculation
Loss attributed to ordinary equity holders of the Company
(d) Weighted average number of ordinary shares
Weighted average number of shares used as the denominator in
calculating basic and diluted earnings per share
2019
$
2018
$
(214,176,963)
(14,526,414)
(200,100,834)
(14,076,129)
(228,703,377)
(214,176,963)
(2.05)
(2.05)
(2.13)
(2.13)
(14,526,414)
(14,076,129)
709,669,029
660,637,923
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, 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.
23. 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.
Producing assets
Production and sale of crude oil, natural gas and associated petroleum products from fields that are in the production phase.
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.
Exploration assets
Exploration and evaluation of permit areas.
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.
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.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
72
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
23. SEGMENT REPORTING (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
Finance costs
Loss before income tax
Taxes
Loss for the year
Segment assets
Segment liabilities
Capital expenditure
PRODUCING
ASSETS
2019
$
EXPLORATION
ASSETS
2019
$
CORPORATE
ITEMS
2019
$
CONSOLIDATION
2019
$
49,657,736
9,700,022
59,357,758
(30,369,092)
28,988,666
122,544
—
—
—
29,111,210
(12,378,327)
(14,802,879)
(7,932,034)
—
—
—
—
—
515
—
—
—
515
—
(999,196)
(40,055)
—
—
—
—
—
261,669
(601,897)
(1,031,636)
(5,194,131)
(6,565,995)
(316,911)
—
(602,742)
49,657,736
9,700,022
59,357,758
(30,369,092)
28,988,666
384,728
(601,897)
(1,031,636)
(5,194,131)
22,545,730
(12,695,238)
(15,802,075)
(8,574,831)
(6,002,030)
(1,038,736)
(7,485,648)
(14,526,414)
—
—
—
—
(6,002,030)
(1,038,736)
(7,485,648)
(14,526,414)
143,022,770
11,067,874
14,659,503
168,750,147
(158,284,408)
(2,991,402)
(13,091,065)
(174,366,875)
Property, plant and equipment
Total capital expenditure
16,077,944
16,077,944
—
—
109,570
109,570
16,187,514
16,187,514
73
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
23. SEGMENT REPORTING (CONTINUED)
2018
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
Other operating expenses
EBITDAX
Depreciation and amortisation
Exploration expenditure
Finance costs
Loss before income tax
Taxes
Loss for the year
Segment assets
PRODUCING
ASSETS
2018
$
EXPLORATION
ASSETS
2018
$
CORPORATE
ITEMS
2018
$
CONSOLIDATION
2018
$
25,458,550
9,480,644
34,939,194
(18,704,042)
16,235,152
—
—
—
—
—
16,235,152
(7,745,236)
(6,027,109)
(7,741,281)
(5,278,474)
—
—
—
—
—
—
504,415
—
—
—
—
504,415
—
(2,762,943)
(28,223)
(2,286,751)
—
—
—
—
—
—
550,769
(1,622,329)
(595,925)
(4,061,759)
—
25,458,550
9,480,644
34,939,194
(18,704,042)
16,235,152
1,055,184
(1,622,329)
(595,925)
(4,061,759)
—
(5,729,244)
11,010,323
(287,856)
—
(493,804)
(8,033,092)
(8,790,052)
(8,263,308)
(6,510,904)
(14,076,129)
—
—
(5,278,474)
(2,286,751)
(6,510,904)
(14,076,129)
121,601,949
12,625,994
24,885,695
159,113,638
Segment liabilities
(136,584,039)
(2,828,327)
(12,637,964)
(152,050,330)
Capital expenditure
Property, plant and equipment
Total capital expenditure
4,433,420
4,433,420
—
—
234,745
234,745
2019
$
4,668,165
4,668,165
2018
$
Revenue from external customers by geographical location of production:
Australia
59,357,758
34,939,194
Non-current assets by geographical location:
Australia
Major Customers
139,164,597
119,350,338
Customers with revenue exceeding 10% of the group’s total hydrocarbon sales revenue are shown below.
Largest customer
Second largest customer
Third largest customer
Fourth largest customer
Fifth largest customer
2019
$
% of Sales
Revenue
2018
$
% of Sales
Revenue
22,706,279
8,829,598
7,153,839
6,362,703
5,695,139
38%
15%
12%
11%
10%
8,665,876
6,948,934
6,314,195
5,250,226
4,008,261
25%
20%
18%
15%
11%
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
74
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
24. PARENT ENTITY INFORMATION
(a) Summary financial information
The individual financial summary statements for the Parent Entity show the following aggregate amounts:
Statement of financial position
Current assets
Non-current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Net assets
Shareholders’ equity
Issued capital
Reserves
Accumulated losses
Total equity
Loss for the year
2019
$
16,127,970
23,291,275
39,419,245
(28,344,300)
(1,032,212)
2018
$
28,495,981
19,431,083
47,927,064
(25,645,024)
(958,070)
(29,376,512)
(26,603,094)
10,042,733
21,323,970
197,776,487
25,310,162
(213,043,916)
197,776,487
23,463,784
(199,916,301)
10,042,733
21,323,970
(13,127,615)
(21,216,129)
Total comprehensive loss
(21,216,129)
Comparative balances for the 2018 year have been amended to reflect the impact of UIG 1052 in accounting for tax balances by individual
entities part of the tax consolidated group.
(13,127,615)
(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).
75
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
25. 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
EQUITY HOLDING
2018
2019
%
%
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
(c) Key management personnel
Disclosures relating to key management personnel are set out in Note 27.
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Units
Ordinary
Ordinary
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
76
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
26. DEED OF CROSS GUARANTEE
On 24 June 2019 Central Petroleum Limited and its wholly owned subsidiary companies entered into a deed of cross guarantee under which
each company guarantees the debts of the others. By entering into the deed, the wholly-owned entities have been relieved from the
requirement to prepare a financial report and directors’ report under ASIC Corporations (Wholly-owned Companies) Instrument 2016/785.
The parties to the deed of cross guarantee are:
-
-
-
-
-
-
-
-
Central Petroleum Limited
Central Petroleum Projects Pty Ltd
Ordiv Petroleum Pty Ltd
Central Petroleum Eastern Pty Ltd
Central Petroleum Services Pty Ltd
Central Petroleum (NT) Pty Ltd
Central Petroleum Mereenie Pty Ltd
Central Petroleum WS (NO 2) Pty Ltd
- Merlin Energy Pty Ltd
- Helium Australia Pty Ltd
- Frontier Oil & Gas Pty Ltd
- Central Geothermal Pty Ltd
- Central Petroleum PVD Pty Ltd
-
- Central Petroleum WS (NO 1) Pty Ltd
Jarl 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 2019.
2019
$
18,046,341
(14,436,725)
3,609,616
354,138
(601,897)
(299,967)
(4,308,910)
(5,194,131)
(15,482,380)
(5,252,743)
(27,176,274)
6,540,518
(20,635,756)
—
(20,635,756)
(194,251,967)
(20,635,756)
(214,887,723)
Revenue from the sale of goods
Cost of sales
Gross profit
Other income
Share based employment benefits
General and administrative expenses
Depreciation and amortisation
Employee benefits and associated costs
Exploration expenditure
Finance costs
Loss before income tax
Income tax credit
Loss for the year
Other comprehensive loss for the year, net of tax
Total comprehensive loss for the year
Retained earnings at the beginning of the financial year
Loss for the period
Retained earnings/(Accumulated losses) at the end of the financial
year
77
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
26. 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 2019.
ASSETS
Current assets
Cash and cash equivalents
Trade and other receivables
Inventories
Total current assets
Non-current assets
Property, plant and equipment
Exploration assets
Intangible assets
Investments
Other financial assets
Deferred Tax Assets
Goodwill
Total non-current assets
Total assets
LIABILITIES
Current liabilities
Trade and other payables
Deferred revenue
Interest-bearing liabilities
Other financial liabilities
Provisions
Total current liabilities
Non-current liabilities
Deferred revenue
Interest-bearing liabilities
Other financial liabilities
Provisions
Total non-current liabilities
Total liabilities
Net assets
EQUITY
Contributed equity
Reserves
Accumulated losses
Total equity
2019
$
17,296,309
3,397,921
1,394,118
22,088,348
65,996,497
8,898,767
72,863
10
2,254,751
5,636,241
3,906,270
86,765,399
108,853,747
13,698,128
1,983,456
6,675,343
38,600
4,380,079
26,775,606
15,119,689
39,223,704
45,033
19,490,789
73,879,215
100,654,821
8,198,926
197,776,487
25,310,162
(214,887,723)
8,198,926
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
78
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
27. KEY MANAGEMENT PERSONNEL
(a) Key management personnel compensation
Short-term employee benefits
Post-employment benefits
Termination benefits
Long-term benefits
Share based payments
2019
$
2018
$
3,120,547
179,537
80,908
(81,319)
(21,388)
2,561,475
139,774
—
59,756
1,097,869
3,278,285
3,858,874
Detailed remuneration disclosures are provided in the remuneration report on pages 28 to 41.
(b) Equity instrument disclosures relating to key management personnel
(i)
Options provided as remuneration and shares issued on exercise of such options
No options were provided as remuneration and no shares were issued on the exercise of options during the current or prior financial
year.
(ii)
Share rights issued under the short term incentive plan
During the year zero cost share rights were issued under the short term incentive plan (“STIP”), in lieu of cash, for certain employees.
The following Share Rights were issued to key management personnel during the year:
STIP RIGHTS
HELD AT START
OF YEAR
RIGHTS RECEIVED
UNDER 2017/18
STIP
CONVERTED TO
SHARES
STIP RIGHTS HELD
AT END OF YEAR
2019
Daniel White
—
83,464
(83,464)
Nil
(iii)
Deferred shares – long term incentive plan
Under the Group’s Employee Rights Plan, eligible employees may receive rights to deferred 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 as
determined by the Board.
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 (“VWAP”) at the start of the plan year.
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:
79
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
27. KEY MANAGEMENT PERSONNEL (CONTINUED)
(iii) Deferred shares – long term incentive plan (Continued)
RIGHTS
HELD AT
START OF
YEAR
MAXIMUM NO.
GRANTED AS
COMPENSATION
CANCELLED
DURING THE
YEAR
CONVERTED
TO SHARES
RETAINED
FOLLOWING
DEPARTURE
Executive Directors and Other Key Management Personnel
Richard Cottee1
Leon Devaney
Ross Evans2
Michael Herrington3
Duncan Lockhart4
Robin Polson5
Daniel White
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
6,952,766
5,307,887
2,985,158
2,373,104
—
N/A
3,380,501
2,886,237
N/A
N/A
—
N/A
2,795,985
2,389,666
183,540
1,854,229
75,089
917,339
778,854
—
980,600
931,057
—
N/A
603,491
—
878,827
767,966
(6,098,087)
(104,675)
(433,335)
(152,643)
—
—
(1,870,478)
(218,397)
—
N/A
—
—
(426,141)
(180,824)
—
(104,675)
(424,754)
(152,642)
—
—
(504,497)
(218,396)
—
N/A
—
—
(417,702)
(180,823)
1,038,2191
N/A
N/A
N/A
N/A
N/A
1,986,126
N/A
N/A
N/A
N/A
N/A
N/A
N/A
RIGHTS
HELD AT
END OF
YEAR
N/A
6,952,766
2,202,158
2,985,158
778,854
—
N/A
3,380,501
—
N/A
603,491
—
2,830,969
2,795,985
1.
Richard Cottee resigned as CEO 31 January 2019 and as a Director on 5 February 2019. 1,038,000 Rights vested and were exercised after resignation. All remaining rights
were cancelled.
2.
Ross Evans commended 1 June 2018
3. Michael Herrington ceased employment effective 29 January 2019. The number of Rights retained following departure represents the maximum number that may vest in the
future subject to vesting and other conditions.
4.
5.
Duncan Lockhart commenced 8 April 2019
Robin Polson commenced 1 May 2018
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
80
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
27. KEY MANAGEMENT PERSONNEL (CONTINUED)
(iv)
Share holdings
The number of shares in the Company held during the financial year by each Director of Central Petroleum Limited and other key
management personnel of the Consolidated Entity, including their personally related parties, are set out below. There were no shares granted
as compensation during the year.
HELD AT
BEGINNING OF
YEAR
HELD AT
DATE OF
APPOINTMENT
SPP & ON
MARKET
PURCHASE
RECEIVED ON
EXERCISE OF
RIGHTS
NET CHANGE
OTHER
HELD AT
DATE OF
DEPARTURE
HELD AT
END OF YEAR
—
N/A
—
—
—
N/A
N/A
—
—
—
—
—
—
—
—
—
—
104,675
424,754
152,642
—
—
504,497
218,396
—
N/A
—
—
501,166
180,823
—
N/A
—
—
—
N/A
N/A
—
—
—
—
—
—
—
—
—
(47,700)
(3,500)
—
—
—
—
—
—
—
N/A
—
—
—
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
664,614
N/A
N/A
315,000
N/A
205,000
N/A
1,750,000
N/A
842,233
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
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
N/A
889,933
1,053,776
629,022
—
—
N/A
572,564
—
N/A
—
—
1,129,989
628,823
Non-Executive Directors
Stuart Baker1
Wrixon Gasteen
Katherine Hirschfeld1
Robert Hubbard2
Martin Kriewaldt3
Peter Moore4
Sarah Ryan3,4
Timothy Woodall5
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
N/A
N/A
293,337
136,473
N/A
N/A
N/A
298,947
1,100,000
N/A
265,000
—
105,000
N/A
1,500,000
N/A
—
N/A
N/A
N/A
200,000
N/A
N/A
N/A
N/A
200,000
—
N/A
N/A
—
N/A
1,000,000
—
N/A
—
156,864
—
N/A
N/A
365,667
—
900,000
50,000
265,000
100,000
105,000
250,000
500,000
Executive Directors and Other Key Management Personnel
Richard Cottee6
Leon Devaney
Ross Evans7
Michael Herrington8
Duncan Lockhart9
Robin Polson10
Daniel White
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
889,933
571,829
629,022
210,000
—
N/A
572,564
250,000
N/A
N/A
—
N/A
628,823
288,000
N/A
N/A
N/A
N/A
N/A
—
N/A
N/A
—
N/A
—
—
N/A
N/A
—
216,929
—
266,380
—
—
104,168
—
N/A
—
—
—
160,000
1
2
Stuart Baker and Katherine Hirschfeld AM were appointed Directors 7 December 2018
Robert Hubbard retired 14 May 2018
3 Martin Kriewaldt and Sarah Ryan were appointed Directors 23 October 2017
4
5
6
7
Sarah Ryan and Peter Moore resigned 13 November 2018
Timothy Woodall was appointed Director 20 December 2017 and resigned 29 September 2018
Richard Cottee ceased employment effective 31 January 2019
Ross Evans commenced 1 June 2018
8 Michael Herrington ceased employment effective 29 January 2019
9
Duncan Lockhart commenced 8 April 2019
10 Robin Polson commenced 1 May 2018
(c) Other transactions with key management personnel
There were no other transactions with Key Management Personnel
81
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
28. RECONCILIATION OF LOSS AFTER INCOME TAX TO NET CASH
OUTFLOW FROM OPERATING ACTIVITIES
Loss after income tax
Adjustments for:
Depreciation and amortisation
Loss/(Profit) on disposal of assets
Profit on disposal of exploration permits
Share-based payments
Financing costs and interest (non-cash)
Changes in assets and liabilities relating to operating activities:
Increase in trade and other receivables
Decrease/(increase) in inventories
(Decrease)/increase in trade and other payables
Increase in deferred revenue
Decrease in financial liabilities
Increase in provisions
2019
$
2018
$
(14,526,414)
(14,076,129)
12,695,238
1,807
—
601,897
1,632,975
8,033,092
(13,799)
(280,000)
1,622,329
1,762,250
(2,429,134)
(1,634,805)
855,954
(829,072)
1,349,706
(38,600)
3,151,005
(302,466)
2,687,060
5,097,991
(38,600)
2,316,307
Net cash inflow from operations
2,465,362
5,173,230
29. CASH FLOW INFORMATION
(a)
Non-cash investing and financing activities
Non-cash interest relating to Other Financial Liabilities amounted to $649,787 (2018: $938,119). Additionally, non-cash revaluation credits
amounted to $163,786 (2018 expense of $414,431). Refer Note 4(a).
Due to a novation of rights and obligations under the MBL Gas Sale and Prepayment Agreement from MBL to IPL in respect of the First
Contract Year, an amount of $nil (2018: $7,865,982) was transferred to Deferred Revenue, reflecting the removal of the cash settlement
option for the First contract year (Refer Note 18 for further details).
(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 Statement of Financial Position are included as the Group considers these to
form part of its net debt.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
82
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
29. CASH FLOW INFORMATION (CONTINUED)
(b) Net debt reconciliation (continued)
Net debt
2019
$
17,805,869
(10,956,896)
(70,773,157)
(63,924,184)
17,805,869
(81,730,053)
(63,924,184)
2018
$
27,222,845
(3,727,338)
(74,599,221)
(51,103,714)
27,222,845
(78,326,559)
(51,103,714)
Other Assets
Liabilities from financing activities
Cash
$
Borrowings
due within 1 year
$
Borrowings
due after 1 year
$
Total
$
5,478,140
(3,606,853)
(78,310,007)
(76,438,720)
21,744,705
4,000,000
—
25,744,705
—
—
(3,710,786)
3,710,786
—
(409,699)
—
(409,699)
27,222,845
(3,727,338)
(74,599,221)
(51,103,714)
(9,416,976)
(3,501,000)
—
(12,917,976)
—
—
(3,826,064)
3,826,064
—
97,506
—
97,506
17,805,869
(10,956,896)
(70,773,157)
(63,924,184)
Cash and cash equivalents
Borrowings – repayable within one year
Borrowings – repayable after one year
Net debt
Cash
Gross debt – variable interest rates
Net debt
Movement in Net Debt
Net debt 1 July 2017
Cash flows
Reclassification of category
Other non-cash movements
Net debt 30 June 2018
Cash flows
Reclassification of category
Other non-cash movements
Net debt 30 June 2019
30. CONTINGENCIES
(a) Contingent liabilities
(i)
Exploration Permits
The Consolidated Entity had contingent liabilities at 30 June 2019 in respect of certain joint arrangement payments. As partial
consideration under the terms of the purchase agreement for EPs 105, 106 and 107, there is a requirement to pay the vendor the
sum of $1,000,000 (2018: $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.
83
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
30. CONTINGENCIES (CONTINUED)
(a)
Contingent liabilities (continued)
(ii) Palm Valley Gas Field Gas Price Bonus (continued)
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, we do not anticipate paying a gas price bonus 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 revisited. Importantly, any future payment of the Gas Price Bonus would only occur where sales and
revenues from the Palm Valley gas field materially exceed our acquisition assumptions.
31. COMMITMENTS
(a) Capital commitments
The Consolidated Entity has the following capital 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
(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
2019
$
2018
$
608,787
—
—
608,787
1,675,020
—
—
1,675,020
12,175,000
46,105,000
4,450,000
6,000,000
14,155,000
13,325,000
11,050,000
—
68,730,000
38,530,000
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.
Commitments for minimum lease payments in relation to non-cancellable operating leases are payable as follows:
Within one year
Later than one year but not later than five years
Later than five years
2019
$
658,188
1,059,047
181,196
1,898,431
2018
$
560,413
1,221,665
—
1,782,078
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
84
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
32. SHARE BASED PAYMENTS
(a) Employee options
An Incentive Option Scheme previously operated to provide incentives for employees. Participation in the plan is at the Board’s discretion;
however, the plan is open to all employees and Directors of the Company.
All remaining options expired or were forfeited during the 2018 year as shown below.
EXPIRY DATE
EXERCISE
PRICE
BALANCE AT
START OF THE
YEAR
GRANTED
DURING THE
YEAR
EXERCISED
DURING THE
YEAR
EXPIRED OR
FORFEITED
DURING THE
YEAR
BALANCE AT
END OF THE
YEAR
VESTED AND
EXERCISABLE
AT THE END OF
THE YEAR
No.
No.
No.
No.
No.
$
2018
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
Totals
$0.450
$0.450
$0.450
$0.400
$0.650
24,900,773
1,466,667
1,800,595
365,100
27,300
28,560,435
Weighted average exercise price
$0.45
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(24,900,773)
(1,466,667)
(1,800,595)
(365,100)
(27,300)
(28,560,435)
$0.45
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(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
2019
22 Mar 2019
30 June 2018
—
1,634,631
$0.130
(1,634,631)
—
—
85
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
32. SHARE BASED PAYMENTS (CONTINUED)
(c) Rights to Deferred shares — Long Term Incentive Plan
Under the Group’s Employee Rights Plan, eligible employees may receive rights to deferred 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 as determined by
the Board.
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 (“VWAP”) at the start of the plan year. Share based payment expense for the year includes amounts expensed in respect of the
following number of rights either granted or expected to be granted:
PLAN YEAR
END
BALANCE AT
START OF YEAR
GRANTED
DURING THE
YEAR
AVERAGE FAIR
VALUE PER
RIGHT
EXERCISED
DURING THE
YEAR
CANCELLED OR
FORFEITED
DURING THE
YEAR
BALANCE AT
END OF YEAR
GRANT DATE
2019
09 May 2019
30 June 2019
17 Apr 2019
17 Apr 2019
24 Sep 2019
24 Sep 2019
02 Oct 2018
27 Jun 2018
16 May 2018
16 May 2018
29 Nov 2017
29 Sep 2017
01 Sep 2017
01 Sep 2017
01 Sep 2017
01 Sep 2017
24 Jan 2017
16 Nov 2016
20 Oct 2016
20 Oct 2016
20 Oct 2016
20 Oct 2016
22 Dec 2015
03 Dec 2015
09 Nov 2015
14 Oct 2015
17 Jun 2015
Totals
30 June 2019
30 June 2019
30 June 2019
30 June 2019
30 June 2016
30 June 2018
30 June 2018
30 June 2018
30 June 2018
30 June 2015
30 June 2018
30 June 2018
30 June 2017
30 June 2016
30 June 2017
30 June 2017
30 June 2017
30 June 2017
30 June 2016
30 June 2016
30 June 2016
30 June 2016
30 June 2016
30 June 2016
30 June 2015
—
—
—
—
—
—
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)
—
—
—
—
—
—
—
—
(384,835)
—
—
—
(1,835,910)
—
(926,672)
(29,510)
—
(161,865)
(165,135)
—
—
—
—
(18,517)
(52,800)
(1,038,000)
(6,063)
(285,881)
—
(3,419,207)
(445,428)
(33,943)
—
(53,866)
(875,873)
—
(222,536)
(2,565,732)
(2,695,755)
(73,429)
—
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
—
—
30,176,669
7,781,809
(4,605,292)
(11,088,670)
22,264,516
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
86
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
32. SHARE BASED PAYMENTS (CONTINUED)
(c) Rights to Deferred shares — Long Term Incentive Plan (continued)
PLAN YEAR
END
BALANCE AT
START OF
YEAR
GRANTED
DURING THE
YEAR
AVERAGE
FAIR VALUE
PER RIGHT
EXERCISED
DURING THE
YEAR
CANCELLED
OR
FORFEITED
DURING THE
YEAR
BALANCE AT
END OF YEAR
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
29 Nov 2017
30 June 2015
29 Sep 2017
30 June 2015
01 Sep 2017
30 June 2018
01 Sep 2017
30 June 2018
01 Sep 2017
30 June 2017
01 Sep 2017
30 June 2016
24 Jan 2017
30 June 2017
16 Nov 2016
30 June 2017
20 Oct 2016
30 June 2017
20 Oct 2016
30 June 2017
20 Oct 2016
30 June 2016
20 Oct 2016
30 June 2016
—
—
—
—
—
—
—
—
—
—
31,655
6,050,315
7,053,384
405,718
28,761
106,666
22 Dec 2015
30 June 2016
1,913,873
03 Dec 2015
30 June 2016
09 Nov 2015
30 June 2016
6,063
521,749
14 Oct 2015
30 June 2016
5,261,487
22 Dec 2015
30 June 2015
191,031
17 Jun 2015
30 June 2015
2,498,256
135,920
6,562
10,306
1,835,910
18,319
239,556
6,124,904
281,250
70,000
327,000
—
—
—
—
—
—
—
—
—
—
—
—
$0.102
$0.126
$0.175
$0.055
$0.084
$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
$0.085
$0.074
—
—
—
—
—
—
—
—
(9,159)
(109,776)
(9,160)
(122,739)
135,920
6,562
10,306
1,835,910
—
7,041
—
6,124,904
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(95,516)
(18,750)
—
—
(6,331)
—
—
(33,333)
(10,244)
—
—
—
(6,666)
—
(95,515)
(1,203,695)
(1,221,132)
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
Totals
24,068,958
9,049,727
(1,418,146)
(1,523,870)
30,176,669
(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
2019
$
2018
$
601,897
1,622,329
87
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
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 statement of financial position 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 and forward-looking interest rates. As the expected loss rate at 30 June 2019 is nil (2018: nil), no
loss allowance provision has been recorded at 30 June 2019 (2018: 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
GROSS
2019
$
2018
$
EXPECTED CREDIT LOSS PROVISION
2018
$
2019
$
Current: 0-30 days
Past due: 31-150 days
Past due: 151-365 days
7,829,994
5,735,333
—
—
—
—
7,829,994
5,735,333
—
—
—
—
—
—
—
—
Based on historic default rates, the Consolidated Entity believes that no impairment allowance is necessary.
The receivables at 30 June 2019 relate predominantly to oil and gas sales which have all been received subsequent to year end.
Credit risk also arises in relation to financial guarantees given by the Parent Entity and other non-borrowing Group entities to certain parties
in respect of borrowings by other Group entities (refer Note 24(b)). Such guarantees are only provided in exceptional circumstances and are
subject to specific Board approval.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
88
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
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 liabilities:
2019
≤ 6 MONTHS
6–12 MONTHS
1–5 YEARS
≥ 5 YEARS
CONTRACTUAL
CASH FLOW
CARRYING
AMOUNT
Financial Assets
Cash and cash equivalents
Trade and other receivables
Other financial assets
17,805,869
7,829,994
—
25,635,863
Financial Liabilities
Trade and other payables
(6,006,532)
—
—
—
—
—
—
—
2,770,782
2,770,782
—
Interest bearing liabilities
(12,232,892)
(4,462,885)
(72,039,417)
Other financial liabilities
—
(2,056,730)
(14,878,886)
(18,239,424)
(6,519,615)
(86,918,303)
—
—
—
—
—
—
—
—
17,805,869
17,805,869
7,829,994
2,770,782
7,829,994
2,770,782
28,406,645
28,406,645
(6,006,532)
(6,006,532)
(88,735,194)
(81,730,053)
(16,935,616)
(15,848,507)
(111,677,342)
(103,585,092)
2018
Financial Assets
≤ 6 MONTHS
6–12 MONTHS
1–5 YEARS
≥ 5 YEARS
CONTRACTUAL
CASH FLOW
CARRYING
AMOUNT
Cash and cash equivalents
27,222,845
Trade and other receivables
Other financial assets
Financial Liabilities
Trade and other payables
Interest bearing liabilities
Other financial liabilities
5,735,333
2,333,333
35,291,511
(8,113,667)
(4,982,834)
—
—
—
—
—
—
—
—
2,535,915
2,535,915
—
(4,827,280)
(81,029,340)
—
(17,050,028)
(13,096,501)
(4,827,280)
(98,002,471)
—
—
—
—
—
—
—
—
27,222,845
27,222,845
5,735,333
4,869,248
5,735,333
4,869,248
37,827,426
37,827,426
(8,113,667)
(8,113,667)
(90,839,454)
(78,326,559)
(17,050,028)
(15,401,106)
(116,003,149)
(101,841,332)
89
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
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
2019
2018
2019
2018
2019
2018
2019
2018
2019
2018
1.3
—
0.9
—
6.8
—
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
Net Financial Assets /
(Liabilities)
Interest Rate Sensitivity
%
%
$
$
1.7
17,805,869
27,222,845
—
1.2
—
—
—
$
—
—
$
—
—
$
—
$
$
$
—
17,805,869
27,222,845
7,829,994
5,735,333
7,829,994
5,735,333
— 1,162,597
3,495,930
1,608,185
1,373,318
2,770,782
4,869,248
17,805,869
27,222,845
1,162,597
3,495,930
9,438,179
7,108,651
28,406,645
37,827,426
—
—
—
7.7 (81,730,053)
(78,326,559)
—
—
—
(81,730,053)
(78,326,559)
—
—
—
—
— (6,006,532)
(8,113,667)
(6,006,532)
(8,113,667)
—
—
— (81,730,053)
(78,326,559)
— (15,848,507)
(15,401,106)
(15,848,507)
(15,401,106)
— (21,855,039)
(23,514,773)
(103,585,092) (101,841,332)
(63,924,184)
(51,103,714)
1,162,597
3,495,930 (12,416,860)
(16,406,122)
(75,178,447)
(64,013,906)
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 amount 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 2018.
PROFIT OR LOSS
EQUITY
10% Increase
10% Decrease
10% Increase
10% Decrease
2019
Cash and cash equivalents
Interest bearing liabilities
2018
Cash and cash equivalents
Interest bearing liabilities
22,596
(558,012)
46,419
(604,182)
(22,596)
558,012
(46,419)
604,182
—
—
—
—
—
—
—
—
These movements would not have any impact on equity other than retained earnings.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
90
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
33. FINANCIAL RISK MANAGEMENT (CONTINUED)
(d) Commodity Risk
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. The effect of potential fluctuations is
not considered material to 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.
Under a Gas Sale & Prepayment Agreement entered into in 2016, the customer may elect for a financial settlement in lieu of taking physical
delivery of gas. The delivery period commences one year after commissioning of the Northern Gas Pipeline. The financial settlement amount
is 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
2019
Other financial liabilities
2018
Other financial liabilities
—
—
919,064
1,040,756
—
—
—
—
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 to show the impact on the carrying value of the financial
liability:
PROFIT OR LOSS
EQUITY
1% Increase
1% Decrease
1% Increase
1% Decrease
2019
Other financial liabilities
2018
Other financial liabilities
(157,649)
157,649
(152,789)
152,789
—
—
—
—
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 five year
partially amortising term loan and has a maturity date of 30 September 2020. Repayments commenced December 2015 and comprise fixed
quarterly principal repayments of $1,000,000 along with accrued interest (excluding the Second Facility D and Facility E repayments - refer
below). The Group does not have any interest rate hedging arrangements in place. Central Petroleum Limited can repay the Facility in part
or in whole at any time without a pre-payment penalty.
In April 2018 Macquarie agreed to an increase in the Facility D Commitment by $5,000,000 (“Second Facility D”). This facility was drawn down
in September 2018 and is repayable in quarterly instalments over calendar year 2019. The outstanding balance of this facility was $2,500,000
as at 30 June 2019.
91
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
33. FINANCIAL RISK MANAGEMENT (CONTINUED)
(e)
Financing Facilities (continued)
In September 2018 Macquarie agreed to increase the facility by a further $7,500,000 (“Facility E”). The facility was drawn down in January
2019 and is repayable over nine monthly instalments which commenced in April 2019. $5,001,000 of this facility remains outstanding as at
30 June 2019.
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
The Net Present Value with a 10% discount rate (“NPV10”) of forecasted net cash flow from the Palm Valley, Dingo and Mereenie gas
fields limited by the sales of only Proved Developed Producing reserves, divided by the outstanding loan amount must be greater
than 1.3:1.
The Group remains compliant with these and all other financial covenants under the Facility.
(f) Currency Risk
The Consolidated Entity’s exposure to currency risk is limited due to its ongoing operations being in Australia and most associated contracts
completed in Australian dollars. A foreign exchange risk arises from oil sales denominated in US dollars and from liabilities denominated in a
currency other than Australian dollars. The Group generally does not undertake any hedging or forward contract transactions as the exposure
is considered immaterial, however, individual transactions are reviewed for any potential currency risk exposure.
At reporting date, the Group had the following exposure to foreign currency risk for balances denominated in US dollars from its continuing
operations, which are disclosed in Australian dollars:
Trade and other receivables
Trade and other payables
2019
$
2018
$
1,922,863
2,129,035
(138,289)
—
The following table details the Group’s 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%
2019
$
(162,234)
198,286
2018
$
(193,549)
212,904
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.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
92
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
34. INTERESTS IN JOINT ARRANGEMENTS
Details of joint arrangements in which the Consolidated Entity has an interest are as follows:
PRINCIPAL ACTIVITIES
OL4, OL5 and PL2 (Mereenie) (Macquarie1)
EP 82 (Santos2)
EP 105 (Santos2)
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
EP 106 (Santos2)
EP 112 (Santos2)
EP 125 (Santos2)
EP 115 North Mereenie Block (Santos2)
EPA 111 (Santos2)
EPA 124 (Santos2)
ATP 2031 (IPL3)
1 Macquarie = Macquarie Mereenie Pty Ltd
2 Santos = Santos Group companies
3 IPL = Incitec Pivot Limited
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration – application
Oil & gas exploration – application
Oil & gas exploration
2019
%
50.00
60.00
60.00
60.00
30.00
30.00
60.00
50.00
50.00
50.00
2018
%
50.00
60.00
60.00
60.00
60.00
30.00
60.00
50.00
50.00
—
The Joint Arrangements are accounted for based on contributions made to the Joint Operated Arrangements on an accruals basis. The
principal place of business is Australia.
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.
In June 2018 an agreement was reached with Incitec Pivot Limited (“IPL”) to form a 50:50 Joint Venture in respect of ATP 2031 effective on
and from the Grant Date. The Queensland government formally awarded the permit to Central in August 2018. Under the agreement
IPL will fund $10 million of the Group’s joint venture obligations ($20 million in total) for appraisal drilling costs during the initial
exploration period.
93
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2019
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 statement of financial position in accordance with the accounting policy described in Note 1(b) under the following
classifications:
2019
$
2018
$
Current assets
Cash and cash equivalents
Trade and other receivables
Inventory
Other financial assets
Total current assets
Non-current assets
Property, plant and equipment
Other financial assets
Total non-current assets
Current liabilities
Trade and other payables
Accruals
Deferred revenue
Total current liabilities
Non-current liabilities
Deferred revenue
Provision for production over-lift
Restoration provision
Total non-current liabilities
Net assets / (liabilities)
Joint arrangement contribution to loss before tax
Revenue
Other income
Expenses
Profit / (Loss) before income tax
509,550
6,224,124
1,325,408
—
8,059,082
57,519,417
301,031
57,820,448
541,019
1,275,441
730,878
2,547,338
439,497
4,008,462
19,594,978
24,042,937
39,289,255
516,573
3,546,014
1,522,351
416,667
6,001,605
50,050,670
393,360
50,444,030
1,083,012
3,273,550
730,878
5,087,440
439,497
3,541,059
12,352,212
16,332,768
35,025,427
42,991,825
22,283
(25,908,972)
17,105,136
25,680,706
29,662
(21,646,937)
4,063,431
35. EVENTS OCCURRING AFTER THE REPORTING PERIOD
The Queensland and Texas court proceedings with Geoscience Resource Recovery, LLC (“GRR”) have settled. The parties filed the relevant
paperwork with the Queensland and Texas courts to finalise ending the legal proceedings. The Group has included a provision for the
settlement of this matter in the financial statements.
The Dukas exploration well in EP112 (100% free carry by Santos) was suspended after encountering much higher than predicted formation
pressures. A forward plan is to be developed over the coming months.
The four well exploration programme in ATP 2031 concluded with encouraging results. Netherland, Sewell & associates (NSAI) has
independently certified 2C contingent resources of 270PJs (100% JV) of Walloons coal seam gas.
No other matter or circumstance has arisen that will affect the Group’s operations, results or state of affairs, or may do so in future years.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
94
DIRECTORS’ DECLARATION
1. In the Directors’ opinion:
a) the financial statements and notes set out on pages 44 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 2019 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 2019.
3. As at the date of this declaration, there are reasonable grounds to believe that the members of the Closed Group identified in note
26 will be able to meet any obligations or liabilities to which they are or may become subject by virtue of the Deed of Cross
Guarantee between the Company and those members of the Closed Group pursuant to ASIC Corporations (Wholly owned
Companies) Instrument 2016/785.
This declaration is made in accordance with a resolution of the Directors of Central Petroleum Limited:
Wrixon Gasteen
Director
Brisbane
25 September 2019
95
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
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 Group) 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 2019 and of its
financial performance for the year then ended
(b)
complying with Australian Accounting Standards and the Corporations Regulations 2001.
What we have audited
The Group financial report comprises:
•
•
•
•
•
•
the consolidated statement of financial position as at 30 June 2019
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 declaration of the directors.
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 and 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.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
96
INDEPENDENT AUDITOR’S 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
• Our audit focused on where
the Group made subjective
judgements; for example,
significant accounting
estimates involving
assumptions and inherently
uncertain future events.
•
The accounting processes are
structured around the Group
finance function located in
Brisbane.
• Amongst other relevant topics,
we communicated the following
key audit matters to the Audit
and Risk Committee:
− Basis of preparation of the
financial report
− Accounting for asset
retirement obligations
•
These are further described in
the Key audit matters section of
our report.
•
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.
• We applied this threshold,
together with qualitative
considerations, to determine
the scope of our audit and the
nature, timing and extent of
our audit procedures and to
evaluate the effect of
misstatements on the financial
report as a whole.
• We chose Group’s total assets
because it is a generally
accepted benchmark in the oil
and gas industry for entities of
a similar size and stage of
development.
• We utilised a 1% threshold
based on our professional
judgement, noting it is within
the range of commonly
acceptable thresholds.
97
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
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
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.
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).
The Group have prepared a going concern position
paper and a cash flow forecast model (the model) which
concludes that the Group is a going concern for a
period of at least 12 months from the date of signing
the financial report. We considered this paper and
model, focussing specifically on:
•
•
•
•
•
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;
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;
Assessed the cash flow forecast by evaluating
the reliability of selected underlying data and
considered selected evidence around key
assumptions in the Group’s cash flow
forecasts;
Performed a sensitivity analysis by varying key
assumptions, including revenue and
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;
Obtained an understanding 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;
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
98
INDEPENDENT AUDITOR’S REPORT
Key audit matter
How our audit addressed the key audit matter
• Read the terms associated with the existing
debt facility agreement and draft terms from
potential financiers and assessed the amount
and terms, including maturity date, of the
facility available;
In relation to the financial statement disclosures, we
considered the going concern basis of preparation
disclosures in note 1 (a) (i) and their consistency with
the Group’s going concern position paper and model.
Accounting for asset retirement obligations
Refer to note 17 of the financial report
Our audit procedures included assessing the
appropriateness of the key assumptions underlying the
rehabilitation provision calculation through:
The Group has legal, environmental or constructive
obligations to rehabilitate sites, either during or at the
end of their operations. The Group have recorded a
provision of $38.8 million for this rehabilitation
obligation at 30 June 2019.
We considered this a key audit matter given that
the estimation of rehabilitation provisions involves
significant judgment by the Group on the required
rehabilitation activities, cost of rehabilitation activities,
timing of rehabilitation, inflation and discount factors,
amongst other matters. Further, the carrying amount of
the provision is material for the Group.
•
•
•
•
•
•
•
•
developing an understanding of the extent of
field development and production activity
through enquiries with operations
management and consideration of site
restoration plans prepared by environmental
experts (the experts);
assessment of the provision calculations to
check that they incorporate the restoration
activities required as advised by the experts
and that the experts’ estimated costs of
conducting those activities are included in the
calculation;
assessment of the competence and objectivity
of the experts;
assessment of the cash flows and production
profiles, and reserve estimation for timing of
rehabilitation;
tested the consistency of the application of
principles and assumptions to other areas of
the audit, such as reserve estimation and
impairment testing,
corroborating a sample of estimates in the
rehabilitation provision calculations to third
party evidence;
tested the mathematical accuracy of the
Group’s present value calculations and
considered the appropriateness of the
discount rate applied in the calculation; and
agreed the calculations to the financial
statements.
99
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
INDEPENDENT AUDITOR’S REPORT
Other information
The directors are responsible for the other information. The other information comprises the
information included in the annual report for the year ended 30 June 2019, but does not include the
financial report and our auditor’s report thereon.
Our opinion on the financial report does not cover the other information and accordingly we do not
express any form of assurance conclusion thereon.
In connection with our audit of the financial report, our responsibility is to read the other information
and, in doing so, consider whether the other information is materially inconsistent with the financial
report or our knowledge obtained in the audit, or otherwise appears to be materially misstated.
If, based on the work we have performed on the other information that we obtained prior to the date of
this auditor’s report, we conclude that there is a material misstatement of this other information, we
are required to report that fact. We have nothing to report in this regard.
Responsibilities of the directors for the financial report
The directors of the Group 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:
http://www.auasb.gov.au/auditors_responsibilities/ar1.pdf. This description forms part of our
auditor's report.
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
100
INDEPENDENT AUDITOR’S REPORT
Report on the remuneration report
Our opinion on the remuneration report
We have audited the remuneration report included in pages 26 to 38 of the directors’ report for the
year ended 30 June 2019.
In our opinion, the remuneration report of Central Petroleum Limited for the year ended 30 June 2019
complies with section 300A of the Corporations Act 2001.
Responsibilities
The directors of the Group 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
25 September 2019
101
CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
ASX ADDITIONAL INFORMATION
DETAILS OF QUOTED SECURITIES AS AT 19 SEPTEMBER 2019
Top holders
The 20 largest registered holders of the quoted securities as at 19 September 2019 were:
NAME
1. UBS Nominees Pty Ltd
2. Citicorp Nominees Limited
NO. OF
SHARES
31,873,994
19,218,035
3. Mr. Christopher Ian Wallin + Ms Fiona Kay McLoughlin + Mrs Sylvia Fay Bhatia 17,571,648
4.
Fanchel Pty Ltd
5. Norfolk Enchants Pty Ltd
6. Rocket Science Pty Ltd
7. Macquarie Bank Limited
8.
J P Morgan Nominees Australia Limited
9. HSBC Custody Nominees (Australia) Limited – A/C 2
10. Kensington Capital Partners Pty Ltd
11. JH Nominees Australia Pty Ltd
12. CS Fourth Nominees Pty Limited
13. Brazil Farming Pty Ltd
14. Morgan Stanley Australia Securities (Nominee) Pty Limited
15. Mr James Donald Bruce Cochrane + Mrs Joan Elizabeth Cochrane
16. Chembank Pty Limited
16. Dynasty Peak Pty Ltd
18. Edwin Holdings Pty Ltd
19. Justwright Investments Pty Ltd
20. Mr Philip Gasteen
17,000,000
16,260,000
15,800,000
14,166,667
11,349,717
8,617,285
7,400,000
6,700,000
6,494,837
5,300,000
5,095,143
5,000,001
5,000,000
5,000,000
4,604,167
4,500,000
4,462,840
%
4.41
2.66
2.43
2.35
2.25
2.19
1.96
1.57
1.19
1.02
0.93
0.90
0.73
0.71
0.69
0.69
0.69
0.64
0.62
0.62
211,414,334
29.27
DISTRIBUTION SCHEDULE
A distribution schedule of the number of holders in each class of equity securities as at 19 September 2019 was:
SIZE OF HOLDING
LISTED FULLY
PAID SHARES
UNLISTED
SHARE RIGHTS
UNLISTED
OPTIONS
NUMBER OF HOLDERS
1 - 1,000
1,001 -5,000
5,001 - 10,000
10,001 - 100,000
100,001 - Over
Total
769
2,000
1,066
2,853
1,000
7,688
—
2
10
54
38
104
—
—
—
—
5
5
SUBSTANTIAL SHAREHOLDERS
Substantial shareholders as disclosed by notices received by the Company as at 19 September 2019 with holdings of 5% or more of the total
votes attached to the voting shares or interests in the Entity:
HOLDER
UNITS
Troy Harry
46,160,000
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
102
ASX ADDITIONAL INFORMATION
UNMARKETABLE PARCELS
Holdings less than a marketable parcel of ordinary shares (being 2,500 shares as at 19 September 2019):
HOLDERS
UNITS
1,790
2,132,120
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.
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 2019 Corporate Governance Statement is dated as at 30 June 2019 and reflects the corporate governance practices in place throughout
the 2019 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/.
103 CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
INTERESTS IN PETROLEUM PERMITS AND PIPELINE
LICENCES AT THE DATE OF THIS REPORT
PERMITS AND LICENCES GRANTED
TENEMENT
LOCATION
OPERATOR
CTP CONSOLIDATED
ENTITY
OTHER JV PARTICIPANTS
Registered
Interest (%)
Beneficial
Interest (%)
Participant
Name
Beneficial
Interest (%)
EP 82 (excl. EP 82 Sub-Blocks) 1
Amadeus Basin NT
EP 82 Sub-Blocks
EP 93 4
EP 97 4
EP 105 1
EP 106 3
EP 107 4
EP 112 1
EP 115 (excl. EP 115 North Mereenie
Block)
EP 115 North Mereenie Block
EP 125
OL 3 (Palm Valley)
Amadeus Basin NT
Pedirka Basin NT
Pedirka Basin NT
Amadeus/Pedirka Basin NT
Amadeus Basin NT
Amadeus/Pedirka Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Santos
Central
Central
Central
Santos
Santos
Central
Santos
Central
Santos
Santos
Central
OL 4 (Mereenie)
Amadeus Basin NT
Central
OL 5 (Mereenie)
L 6 (Surprise)
L 7 (Dingo)
RL 3 (Ooraminna)
RL 4 (Ooraminna)
ATP 909
ATP 911
ATP 912
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Georgina Basin QLD
Georgina Basin QLD
Georgina Basin QLD
ATP 2031 6
Surat Basin QLD
Central
Central
Central
Central
Central
Central
Central
Central
Central
60
100
100
100
60
60
100
30
100
60
30
100
50
50
100
100
100
100
100
100
100
50
60
100
0
0
60
60
0
30
100
60
30
100
50
50
100
100
100
100
100
100
100
50
Santos QNT Pty
Ltd (“Santos”)
Santos
Santos
Santos
Santos
Santos
Macquarie
Mereenie Pty
Ltd (“Macquarie
Mereenie”)
Macquarie
Mereenie
40
40
40
70
40
70
50
50
Incitec Pivot
Queensland Gas
Pty Ltd
50
PERMITS AND LICENCES UNDER APPLICATION
TENEMENT
LOCATION
OPERATOR
CTP CONSOLIDATED
ENTITY
OTHER JV PARTICIPANTS
Registered
Interest (%)
Beneficial
Interest (%)
Participant
Name
Beneficial
Interest (%)
EPA 92
EPA 111 2
EPA 120
EPA 124 2 & 5
EPA 129
EPA 130
EPA 131 4
EPA 132
EPA 133
EPA 137
EPA 147
EPA 149
EPA 152 5
EPA 160
EPA 296
Lander Trough NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Lander Trough 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
Lander Trough NT
Lander Trough 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
100
100
100
100
100
100
100
100
100
Santos
Santos
50
50
2019 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
104
INTERESTS IN PETROLEUM PERMITS AND PIPELINE
LICENCES AT THE DATE OF THIS REPORT
PIPELINE LICENCES
PIPELINE LICENCE
LOCATION
OPERATOR
CTP CONSOLIDATED
ENTITY
OTHER JV PARTICIPANTS
Registered
Interest (%)
Beneficial
Interest (%)
Participant
Name
Beneficial
Interest (%)
PL 2
PL 30
Notes:
Amadeus Basin NT
Amadeus Basin NT
Central
Central
50
100
50
100
Macquarie
Mereenie
50
1
2
3
4
Santos’ right to earn and retain participating interests in the permit is subject to satisfying various obligations in their farmout agreement with Central. The participating interests
as stated assume such obligations have been met, otherwise may be subject to change.
Effective 1 May 2017, Santos exercised its option to acquire a 50% participating interest in and be appointed operator of EPA 111 and EPA 124, which was granted as part of
Central’s acquisition of a 50% interest in the Mereenie oil & gas field.
Santos (as Operator) has continued the process of an application with the NT Department of Primary Industry and Resources for consent to surrender Exploration Permit 106.
These exploration permits and exploration permit applications and have been disposed, with transfers for the granted exploration permits undergoing the process of registration
with the NT Department of Primary Industry and Resources.
5 On 22 March 2018 (in respect EPA 124) and on 23 March 2018 (in respect of EPA 152) Central received notice from the NT Department of Primary Industry and Resources that
EPA 124 and EPA 152, as applicable, had been placed in moratorium for a period of 5 years from 6 December 2017 until 6 December 2022.
6
As per Central’s announcement dated 29 August 2018, Central was granted ATP 2031. As per Central’s announcement dated 25 June 2018 ATP 2031 is subject to a 50:50 joint
venture with Incitec Pivot.
105 CENTRAL PETROLEUM LIMITED 2019 ANNUAL REPORT
Central Petroleum Limited
ACN 083 254 308
Head Office
Level 7, 369 Ann Street, Brisbane, Qld 4000
Postal Address
GPO Box 292, Brisbane, Qld 4001
Email: info@centralpetroleum.com.au
www.centralpetroleum.com.au