Cenntraal PPetrroleeumm Limitedd
ACNN 0883 2554 3308
2001188 ANNUAAL REEPORT
TABLE OF CONTENTS
CORPORATE DIRECTORY ................................................................................................................................................... 1
CHAIRMAN’S LETTER ........................................................................................................................................................ 2
ACTING CHIEF EXECUTIVE OFFICER’S LETTER ................................................................................................................... 3
DIRECTORS’ REPORT ......................................................................................................................................................... 4
AUDITOR’S INDEPENDENCE DECLARATION .................................................................................................................... 33
CORPORATE GOVERNANCE STATEMENT ........................................................................................................................ 34
FINANCIAL REPORT ......................................................................................................................................................... 35
CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME ........................................... 36
CONSOLIDATED STATEMENT OF FINANCIAL POSITION ................................................................................................... 37
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY ................................................................................................... 38
CONSOLIDATED STATEMENT OF CASH FLOW ................................................................................................................. 39
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS .............................................................................................. 40
DIRECTORS’ DECLARATION ............................................................................................................................................. 84
INDEPENDENT AUDITOR’S REPORT ................................................................................................................................ 85
ASX ADDITIONAL INFORMATION .................................................................................................................................... 90
INTERESTS IN PETROLEUM PERMITS AND PIPELINE LICENCES AT THE DATE OF THIS REPORT ...................................... 92
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
CORPORATE DIRECTORY
DIRECTORS
Martin Kriewaldt BA, LL.B (Hons 1st), FAICD (Life), Non-executive Chairman (appointed 23 October 2017)
Richard Cottee BA, LLB (Hons), Managing Director and Chief Executive Officer
Wrixon F Gasteen BE(Mining) (Hons), MBA (Distinction), Non-executive Director
Dr Peter S Moore BSc (Hons 1st), MBA, PhD, GAICD, Non-executive Director
Dr Sarah Ryan, PhD, BSc (Hons 1st), BSc, FTSE, MAICD, Non-executive Director (appointed 23 October 2017)
Tim Woodall, B. Econ, FCPA, GAICD, Non-executive Director (appointed 20 December 2017)
GROUP GENERAL COUNSEL AND JOINT COMPANY SECRETARY
Daniel C M White LLB, BCom, LLM
JOINT COMPANY SECRETARY
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:
Facsimile:
www.computershare.com.au
+61 7 3237 2110
+61 3 9473 2085
STOCK EXCHANGE LISTING
Central Petroleum Limited shares are listed on the Australian Securities Exchange under the code CTP.
1
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
CHAIRMAN’S LETTER
A MESSAGE FROM MARTIN KRIEWALDT
Dear Fellow Shareholders
Much has changed for Central since our last review in September 2017 covering the Financial Year 2017. Financial Year 2018 has seen the
Company successfully complete a number of the objectives outlined at that time:
Pipeline tariff reform in respect of monopolies either from ownership or from capacity hoarding. The significant reforms legislated will
assist in bringing gas to the markets at reasonable returns to those who have invested capital in building the pipelines, but remove any
incentive to leave that capacity idle for any reason;
The signing of a Gas Sales Agreement (“GSA”) with Incitec Pivot Ltd (“IPL”) for the sale of a significant gas volume through 2019—which
has helped to keep IPL’s Gibson Island Plant open—represents a significant step change in Central’s financial position;
A separate agreement with IPL under which IPL funds Central under a $20 million farm-in to explore for gas in a new licence area in
Queensland. Following that farm-in, IPL and Central will own any production and associated licences 50:50;
Raising $27 million in funds through the rights issue to fund appraisal drilling and plant improvement;
Commencement of work on upgrading our jointly owned Mereenie Plant and our Palm Valley Plant to deliver gas to new customers;
Commencement of a drilling programme with the drilling of West Mereenie 26 and the preliminary work for permits to drill Palm
Valley 13;
The successful board succession programme with the appointment of Dr Sarah Ryan, Tim Woodall and me to the board, the retirement
of Rob Hubbard from the board and its chairmanship and my appointment as replacement chairman. The board now has a wide range
of oil industry experience as well as strong board experience.
The first three of these tasks are company-making for Central, given our gas producing assets are far removed from the main market for gas
users. Following these reforms, we anticipate that Central’s gas can be sold into the east coast at a price that provides gas suppliers with an
incentive for new exploration and also reduces the demand destruction that would have otherwise occurred. Importantly, Central’s gas can
now be sold to Australian east coast users at a profit.
The alignment with IPL to explore for gas in Queensland is a wonderful example of management seeing the synergies of a combination of IPL
and Central. The Queensland Government recognised the power of the combination in awarding the new area to Central and IPL.
As I write this, your Company is now fully focused on completing the plant upgrades necessary to make sure we deliver the gas we have sold
to IPL and others. The drilling at Palm Valley is underway. On conclusion of the upgrades, your Company will be moving to the second phase
of its strategy to grow its reserves and its sales to customers, the drilling being one aspect of that.
It has been a year of great achievements by the Central management team. I wish to thank all of them, including our new additions to the
senior team, for their hard work throughout the year.
During the year and shortly after its conclusion, there have been two significant departures from Central.
Rob Hubbard chaired your Company through difficult times financially and the takeover bid. Neither task was easy. It is a credit to him that
he remained at the helm during this period.
Richard Cottee has dominated the gas industry for many years and your Company has been fortunate to have his energy and strident
advocacy as it progressed its strategy to get its gas to market profitably. His personality made it certain the Company view would be heard,
despite our minnow status. His persistent pressure to achieve the reforms so necessary for the country and Central undoubtedly played a
significant part in what has been achieved.
Richard leaves behind the completed first stage of Central’s strategy and the template for further growing the Company’s reserves, sales
and, of course, value.
I thank them both for their contribution to the successful launch of a new player in the gas sales market, one with a big future, in my opinion.
Martin Kriewaldt
Chairman
Brisbane
28 September 2018
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
2
ACTING CHIEF EXECUTIVE OFFICER’S LETTER
Dear Fellow Shareholders
I would like to begin this letter by recognising the recent change that has taken place within the CEO role. Richard Cottee and the management
team at Central have worked hard over the past five years to develop and position your Company’s strategy of creating shareholder value by
connecting its significant potential gas resources in the Northern Territory to the east coast gas market that remains in critical short supply.
Richard provided leadership, energy and creativity that was critical in taking on such a transformative strategy, particularly the adept handling
of many obstacles along the way. On a personal note, I thoroughly enjoyed taking this journey with him.
Following Richard’s departure, I have taken up the role of Acting CEO. Together with the management team, Central remains committed to
executing your Company’s strategy to create value for all shareholders. Recognising the importance of our stakeholders and partners to our
business, Central’s team will continue to build on our engagement with, and commitment to, the traditional owners, the communities where
we operate and our gas customers.
Over the past financial year, Central has materially progressed its Gas Acceleration Programme (“GAP”) and strategy to be on the cusp of
being a significant supplier into the east coast gas market following completion of the Northern Gas Pipeline (“NGP”) scheduled for
December 2018. Some of the notable milestones for the Company since the start of the 2018 financial year include:
1) Gas Acceleration Programme: Following our successful $27 million equity raise in September 2017, our approach to deliver the GAP
evolved to include facility upgrades at Mereenie and Palm Valley, as well as appraisal drilling. With our target now in sight of having
increased gas volumes (reserves and production capacity) available for sale into the NGP, Central remains fully focused on completing
the facility upgrades and appraisal drilling programme as safely and as cost effectively as possible.
2)
IPL Gas Supply Agreement: Central entered into a new GSA with IPL in June 2018 for 20 TJ/d commencing on completion of the NGP
later this year. The IPL GSA is our first gas sales agreement into the east coast market and upon commencement, will contribute to
an almost tripling of our gas sales under contract. This will fundamentally change the future financial performance of your Company,
notably a significantly stronger cash flow.
3) ATP 2031 Permit Award: On 1 March 2018, the Queensland Department of Natural Resources, Mines and Energy announced Central
was the preferred bidder for ATP 2031. This 77 km2 permit is located within the prospective Queensland Surat Basin coal seam gas
region and is approximately 28 km north-west of the town of Miles. The permit was formally granted to Central on 28 August 2018.
It is contemplated that the acreage could ultimately help to support the long term viability of IPL’s Gibson Island fertiliser facility in
Queensland. As part of the arrangement, Central and IPL will establish a 50:50 joint venture whereby IPL will fund up to $20 million
for the exploration programme.
4)
Local and Indigenous Employment: Our employment philosophy, first established in March 2015, has achieved a good balance
between local and Fly-in Fly-out (“FIFO”) workers whilst continuing to deliver excellent safety and environmental performance. Our
employment mix continues to be one third local indigenous, one third local non-indigenous and one third FIFO. This is a dramatic
turnaround from September 2015 when Central assumed operatorship of Mereenie oil and gas field with its workforce at 93% FIFO.
5) Pipeline Reforms: There has been significant reform in the pipeline sector addressing both monopolistic pricing and capacity
hoarding. The implementation of these reforms will largely occur over the next 12 months, during which time we would anticipate
seeing the benefits of these reforms become visible to gas customers and suppliers. We have already seen some downward pressure
in pipeline tariffs. Whilst in our view these reforms did not go far enough, we are optimistic that they will bring a material
improvement to this critical part of the gas market;
6) Management Team: We have significantly augmented our management team in order to add capacity and capability to the team,
deliver our current projects, and achieve our future growth objectives. This has included Ross Evans as Chief Operations Officer,
Robin Polson as Chief Commercial Officer and Ben Visser as General Manager Operations.
In summary, we have been on a journey spanning several years with a focus to create real value for Central’s shareholders. We have made
enormous strides in delivering this vision and now stand poised to start reaping the benefit of this effort. In a year’s time, we expect to be
delivering significant volumes of gas into the east coast gas market, generating strong positive cash flows and embarking on new and exciting
growth opportunities.
Leon Devaney
CEO (acting)
Brisbane
28 September 2018
3
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
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 2018.
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.
Robert Hubbard (retired 14 May 2018)
Martin D Kriewaldt (appointed 23 October 2017)
Richard I Cottee
Wrixon F Gasteen
Peter S Moore
Sarah Ryan (appointed 23 October 2017)
Timothy R Woodall (appointed 20 December 2017)
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 (2017: $Nil). No recommendation for payment of dividends has been made.
OPERATING AND FINANCIAL REVIEW
Operating Highlights
The Company’s focus and achievements for the year were as follows:
A 46% increase in gas sales volumes and a 41% increase in total sales revenue.
Cash flow from operations of $5.2 million compared to a $0.2 million outflow in the prior year.
An equity raising was successfully completed in September 2017 to support the Gas Acceleration Programme, raising $27 million.
The ACCC granted authorisation for Mereenie Joint Marketing arrangements between Central and Macquarie Mereenie for
three years.
The Queensland Government announced that Central’s wholly owned subsidiary, Central Petroleum Eastern Pty Ltd, was the
preferred bidder for Queensland acreage (ATP(A) 2031). The permit lies within the north-eastern Walloon Fairway, surrounded by
acreage held by QGC, Arrow and APLNG. Subsequent to year end, in August 2018, the permit was formally awarded to Central.
West Mereenie 26 appraisal well spudded on 22 May 2018 and was in progress at 30 June 2018.
A Gas Sales Agreement (“GSA”) was executed with Incitec Pivot Limited (“IPL”) whereby Central will deliver at least 20 TJ/day of
gas to IPL on an ex-field basis from its Palm Valley and Mereenie fields. The gas will be delivered from the commencement of
commercial operations on the Northern Gas Pipeline until 31 December 2019.
A 50:50 joint venture arrangement for ATP(A) 2031 in Queensland was agreed with IPL, allowing the fast tracking of the Queensland
acreage. IPL will contribute up to $20 million for appraisal drilling costs during the initial exploration period.
The Company’s management team was strengthened with the appointment of Ross Evans as Chief Operating Officer and Robin
Polson as Chief Commercial Officer.
Joint Venture approval was obtained for an expansion project at Mereenie to increase gas deliverability into the Northern Gas
Pipeline (“NGP”).
Santos completed acquisition of 403 km of seismic data, infilling the previous 932 km of seismic acquired in 2016 and bringing the
total to 1,335 km, meeting the requirements of the Stage 2 Farm-in in the Southern Amadeus Basin. The additional seismic lines
reduce dip line spacing over the Dukas prospect to approximately 5 km between dip lines over the central prospect area, and
approximately 10 km towards the flanks. Processing of the acquired seismic data has commenced and continues.
Third party environmental audits were conducted at Palm Valley and Dingo with no non-conformances noted.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
4
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Operating Result
The Consolidated Entity had an operating loss after income tax for the year ended 30 June 2018 of $14.08 million (2017: loss of
$24.73 million). Underlying EBITDA1 for the Consolidated Entity was $2.21 million (2017: $0.32 million). In addition, non-cash share based
payment expense included in the above results amounted to $1.62 million (2017: $2.25 million).
1
EBITDA is earnings before interest, taxation, depreciation, amortisation and impairment.
Granted Petroleum Production and Retention Licences in which the Company has an interest.
Key results for the reporting period were:
Sales Volumes of 4,842 TJ of gas (2017: 3,322 TJ) and 105,619 barrels of crude oil (2017: 111,380 barrels). The increase in gas sales
reflects a full year contribution from the Energy Developments Limited (“EDL”) gas contract.
Sales Revenue of $34.94 million, up 41% on the previous financial year, reflecting increased production as a result of the full year
contribution of the EDL contract and an increase in the average realised oil price as a result of increases in world crude prices, but
partly offset by a higher AUD:USD exchange rate.
Underlying loss1 of $13.67 million, down from an underlying loss of $15.27 million in the prior year, a 10% improvement.
Exploration expenditure increased to $8.79 million in financial year 2018 from $1.90 million in financial year 2017 reflecting the
appraisal drilling programme in progress at year end.
Net cash flow from operations of $5.17 million, an improvement from a net cash outflow in 2017 of $0.2 million. Cash flows for
financial year 2017 do not reflect any contribution from the new EDL sales contract which commenced in June 2017.
1 Underlying loss after tax can be reconciled to statutory loss after tax as follows:
Statutory loss after tax
Add/(less):
R&D refunds
Restatement of financial liabilities1
Impairment of exploration assets
Impact with Total GLNG withdrawal from Southern Georgina Joint Venture (net of
restoration liabilities)
One off items of corporate expenditure
Underlying loss after tax
2018
$ million
2017
$ million
(14.08)
(24.73)
—
0.41
—
—
—
(0.63)
9.49
0.09
(1.19)
1.70
(13.67)
(15.27)
1
5
Relates to a prepaid gas sales agreement containing a cash settlement option. If the cash settlement option is exercised, (instead of physical delivery of gas), payment
will be satisfied out of future gas sales revenues from those gas sales agreements to which the cash settlement option is linked. Refer Note 3(b) to the Financial
Statements for further explanation.
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Financial Review
The Company’s financial position improved during the year ended 30 June 2018, with the underlying loss reduced by 10% on the previous
financial year.
Key Metrics
Net Sales Volumes
Oil (barrels)
Natural Gas (TJ)
Sales revenue ($ million)
Underlying EBITDAX ($ million)
Underlying EBITDA ($ million)
Underlying Loss ($ million)
Statutory loss (after tax)
Cash ($ million)
*
A positive percentage reflects an improvement over the previous year.
2018
2017
Percentage
Change*
105,619
111,380
4,842
34.94
11.00
2.21
(13.67)
(14.08)
27.22
3,322
24.79
2.22
0.32
(15.27)
(24.73)
5.48
(5)%
46%
41%
395%
591%
10%
43%
397%
Additional Information:
1. Mereenie oil converted at 5.816 GJ/BOE
2.
Central had no production prior to April 2014
EBITDAX/EBITDA
Underlying earnings before interest, tax, depreciation and amortisation (“EBITDA”) was $2.21 million, compared to $0.32 million in the prior
year. Underlying EBITDA and exploration (“EBITDAX”) was $11.00 million, compared to $2.22 million in the prior year.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
6
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Take or Pay
Gas sales from Dingo did not achieve full contracted volumes as the customer continued to take gas below the Annual Contract Quantity.
Dingo Take-or-Pay cash receipts of $5.0 million were received for the contract year to 31 December 2017 and were not recognised as
accounting revenue during the reporting period. This will be accounted for as revenue in future periods in accordance with the Group’s
revenue recognition policy (refer Note 1(e)(i)).
A reconciliation of underlying EBITDAX and EBITDA is shown below.
Underlying loss after tax
Add/(less):
Exploration
Net interest
Income tax
Depreciation and amortisation
Underlying EBITDAX1
Underlying EBITDA1
2018
$ MILLION
2017
$ MILLION
(13.67)
(15.27)
8.79
7.85
—
8.03
11.00
2.21
1.90
7.81
—
7.78
2.22
0.32
1 Underlying EBITDA and EBITDAX includes a non-cash share based payment expense of $1.62 million (2017: $2.25 million)
Gas deliveries under the EDL contract commenced in June 2017. Underlying EBITDA for 2017 therefore reflects only one month supply under
this new gas sales contract.
Sales Volumes
Mereenie gas sales volumes increased from 2017, reflecting a full year contribution from the EDL gas sales contract which commenced in
June 2017.
Palm Valley gas field: In order to maintain operational efficiency and capacity across all assets the Palm Valley field was placed on 24-hour
standby during 2016, with contracts being delivered from the Mereenie and Dingo fields.
Dingo gas field: In accordance with the Power and Water Corporation Gas Sales Agreement, revenue associated with Take-or-Pay during the
2017 calendar year was received in January 2018 but is yet to be recognised as income in accordance with the Group’s revenue recognition
accounting policy (refer Note 1(e)(i)).
Commodity Prices
Central’s gas prices generally reflect long-term fixed gas pricing structures with CPI related escalation, and are therefore not impacted by
global energy markets. In line with the increase in world crude oil prices, but partly offset by a higher Australian dollar, the average realised
price of oil increased from the previous financial year.
Other Income
Other income for financial year 2018 included the sale of exploration permits amounting to $0.28 million along with $0.21 million from the
sale of items of drilling inventory.
In the 2017 Total withdrew from the Southern Georgina Farmout. This resulted in the extinguishment of accrued liabilities amounting to
$2.02 million recognised in other income during the 2017 financial year.
Restatement of Financial Liabilities
The statutory loss for the year ended 30 June 2018 includes a non-cash expense of $0.41 million (2017: $9.49 million) relating to the
revaluation of financial liabilities associated with the Gas Sale and Prepayment Agreement with Macquarie Group which contains an option
for Macquarie to elect a cash settlement in lieu of physical delivery of gas. The cash settlement amount, if opted for, is linked to the ex-field
price of new Gas Sales Agreements entered into by the Group and supplied from the Mereenie, Dingo or Palm Valley fields. Refer to Note 3(b)
to the financial statements for further explanation of this non-cash expense.
General and Administrative Expenses
General and administrative expenses net of recoveries decreased from $1.95 million in fiscal year 2017 to $0.60 million in fiscal year 2018.
The decrease was largely a result of one off costs associated with the proposed Scheme of Arrangement incurred in the 2017 financial year.
7
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Employee Benefits and Associated Costs
Employee costs, net of recoveries for operational and exploration activities, decreased to $4.06 million from $5.66 million in the previous
financial year. Gross costs before recoveries increased 2.3% reflecting annual remuneration increases. Recoveries from exploration and
production operations were higher as a result of increased activity including new capital projects and the appraisal drilling programme.
Cash
At 30 June 2018, consolidated cash and cash equivalents available totalled $27,222,845 (2017: $5,478,140), including $516,572
(30 June 2017: $396,972) held in joint venture bank accounts. Of this balance $1,782,026 relates to cash held with Macquarie Bank Limited
to be used for allowable purposes under the Facility Agreement (2017: $1,421,848), including, but not limited to operating costs for the
Palm Valley, Dingo and Mereenie fields, taxes, and debt servicing.
Gearing
The consolidated debt ratio at 30 June 2018 was 0.49 (2017: 0.60). Debt ratio is defined as Total Debt / Total Assets. The Consolidated Entity’s
debt funding is supported by long-term gas sales contracts. Total borrowings decreased from $82.17 million at 30 June 2017 to $78.33 million
at 30 June 2018 as the consolidated entity continues to make quarterly principal and interest repayments.
Capital Expenditure
Capital expenditure for fiscal year 2017 was $4.68 million, up from $0.96 million in 2017. Expenditure for the year included $2.37 million on
the Mereenie Expansion project in progress at year end and $0.69 million on the Dingo glycol dehydration unit.
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.
2018
$ MILLION
2017
$ MILLION
2016
$ MILLION
2015
$ MILLION
2014
$ 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 (GJ)
Oil Sales (barrels)
34.94
8.79
14.08
25.47
103.85
(78.33)
7.06
17.19
24.79
1.90
24.73
—
106.82
(82.17)
(5.96)
0.73
23.86
4.03
21.04
11.52
113.78
(85.70)
16.52
5.33
10.31
7.66
27.73
5.56
58.58
(47.46)
23.15
(4.41)
4,842,047
105,619
3,321,731
111,380
3,230,473
98,635
1,194,153
53,925
No. of employees at 30 June
89
83
83
58
3.72
4.66
10.86
24.97
46.27
(23.76)
43.07
2.78
267,328
17,489
51
Risks
Central was admitted to the ASX in 2006 and since that time has been exploring for, and more recently producing, oil and gas from onshore
central Australia.
General Risks
As with most businesses, Central is exposed to a number of general risks that could materially affect its financial position, assets and liabilities,
reputation, profits, prospects and share price. These could include:
fluctuations in economic conditions in Australia and internationally, including fluctuations in economic growth, interest rates,
exchange rates, inflation, and employment;
fluctuations in stock markets, domestically and internationally;
changes in government policies including fiscal policy, monetary policy, and foreign policy;
changes in political conditions; and
natural disasters and catastrophic events.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
8
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Cash Flow and Liquidity Risk
Central’s ability to meet its debts as and when they are due for payment depends on future performance and cash flow from its operations.
These cash flows may be affected by broader economic, financial, competitive, legislative and other factors, many of which are beyond the
control of the Board of Directors.
Exploration and Appraisal Risk
By its nature, exploration is a high risk business. Most exploration activity, in particular seismic and drilling, is conducted in joint ventures,
thus enabling the joint venture participants to spread that risk, and reward. The risks include, but are not limited to, land access risk,
geological risk, drilling operations risk, safety and environmental risks. In addition, as with most businesses, there is also market risk, product
pricing risk and foreign exchange risk.
Central’s activities are subject to extensive government regulation in areas such as exploration rights, drilling practices, environmental
performance and workplace health and safety. Central regularly monitors changes in government regulation.
Oil and Gas Estimates
Reservoir engineering is subjective and can only provide an educated estimate of the extent of oil and gas reserves in place. Estimates are
not precise and are based not only on knowledge, but experience, interpretation and accepted industry practice. There are a number of
variables that can impact economically recoverable reserves, including changes to government regulations, commodity prices and taxes.
Environmental Risk
Central is subject to laws and regulations to minimise the impact of environmental damage arising from its operations. Non-compliance with
these laws and regulations can result in substantial penalties and remediation costs. Any change in the laws or regulation may adversely
affect Central’s business.
Operating and Insurance Risks
Central’s key operating risks include governmental regulatory compliance, changes in operating costs, changes in capital maintenance and
replacement costs, plant availability and sub-surface extraction. In addition, Central is exposed to changes in $A commodity prices with
respect to crude oil sales which are benchmarked against $US international markets. The majority of Central’s revenues, however, are
generated by gas sales which effectively mitigates $A commodity price risk through the use of long-term, $A fixed price gas sales agreements
with credit worthy customers.
The oil and gas industry is hazardous by nature with many inherent risks including potential well blowouts, spills and leaks, ruptures and
pollutants. Central maintains insurance cover for the key risks, however full insurance cover may not be available or may be cost prohibitive
and as a result any losses Central sustains may only be partially covered by insurance, if at all.
Presently, Central’s key risks relating to capital expenditure stem from its ongoing appraisal drilling campaign and its surface facility projects
at Mereenie and Palm Valley.
Competition and Human Resource Risk
Central competes with numerous other oil and gas producers that have substantially greater financial resources, staff and facilities.
The ability to secure transportation of its product remains a key factor in its competitiveness within the industry.
Central’s credentials as an oil and gas explorer and producer are reliant on its ability to attract talented staff and professional service
contractors, competing with other larger organisations. Any growth in demand for skilled employees and professional service contractors
may adversely impact Central’s ability to attract and retain these people.
Health, Safety and Security Risks
The oil and gas industry by its nature has many inherent health and safety risks. Central maintains a strong focus on the health and safety of
all those involved or affected by its operations, however the risk of personal injury is always present.
In addition to personal harm, a serious incident may result in reputational damage, the ability to attract and retain employees as well as
compensation, regulatory fines and penalties.
Pipeline Tariff Risk
Central will be selling gas into the east coast market following commencement of the Northern Gas Pipeline (“NGP”) scheduled for late 2018.
The east coast gas market is currently undergoing a restructuring of supply and demand following the commencement of three LNG projects
in Queensland. This has placed significant upward pressure on delivered gas prices to the east coast. Central’s ex-field gas price for sales into
the east coast however, will in part, depend upon pipeline tariffs which are themselves undergoing regulatory review and reform by Federal
Government agencies. The outcome of these pipeline reviews and gas market dynamics may be material to Central’s ex-field gas pricing
received from east coast customers.
9
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Business Strategy
Over the past three years, Central has developed and successfully pursued a strategy to take advantage of a tightening domestic gas market
to gain critical mass in conventional gas production and uncontracted gas reserves. This strategy first commenced through the acquisition of
the Palm Valley and Dingo gas fields from Magellan in April 2014, marking Central’s entry into commercial gas production.
Central’s business strategy was bolstered significantly on 1 September 2015 when Central completed the acquisition of 50% of Mereenie
from Santos and became Operator for the Joint Venture. The implementation of this business strategy has made Central a substantial onshore
domestic gas producer, with approximately 17.2 TJ/d (6.3 PJ p.a.) equity accounted from sales contracts being delivered at 30 June 2018.
Central is currently undertaking an appraisal drilling programme to increase uncontracted 2P reserves. Whilst the results of the first appraisal
well (WM 26 at Mereenie) were disappointing, we will be conducting a technical review to evaluate opportunities to enhance productivity
from the target zones. The PV 13 appraisal well at Palm Valley spudded during August 2018. Whilst resources associated with appraisal wells
are brownfield and could be available for delivery into the east coast market from late 2018 via the NGP, completion of certification of the
reserves will take longer and occur over time. Both the Mereenie and Palm Valley fields are undergoing substantial surface facility upgrade
projects designed to maximise sales capacity and accelerate delivery of existing 2P reserves.
With the Mereenie, Palm Valley and Dingo fields under our common operatorship, Central is now in a unique position to utilise (and actively
support) the NGP, which will connect the Northern Territory to the eastern seaboard in late 2018. This project is driven by clear fundamentals
of a domestic gas shortfall on the east coast and underexplored onshore gas potential in the Northern Territory. In linking supply and
demand, Central’s business strategy of acquiring gas assets and uncontracted reserves in advance of the NGP pipeline positioned it to be a
direct beneficiary.
The acquisition of Palm Valley, Dingo, and Mereenie were based on existing long-term gas contracts which incorporate fixed prices with CPI
escalation. More recent GSAs have also been structured on a similar fixed price basis. This provides a solid revenue stream going forward to
cover Central’s operating activities. In addition, debt financing arrangements are secured via these long term gas contracts with pricing not
affected by oil price or currency movements and are therefore largely unaffected by 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.
Accessing new and higher-value markets for our gas could re-rate our significant under-explored permits throughout the Amadeus,
Southern Georgina, Pedirka and Wiso basins in Central Australia. Going forward, our operations are expected to be cash flow positive after
debt service which allows us to focus capital on value accretive exploration and appraisal activities.
Granted Petroleum Permits, Licences and Application Interests
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
10
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Operations and Activities
Sales Volumes (Central Petroleum’s Share)
Product
Gas
Crude and Condensate
Unit
TJ
bbls
FY 2017/18
FY 2016/17
4,842
105,619
3,224
111,380
PRODUCING ASSETS
Mereenie Oil and Gas Field (OL4 and OL5)
Northern Territory
(CTP—50% Interest [Operator], Macquarie Mereenie Pty Ltd—50% Interest)
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. With the upcoming commissioning of the Northern Gas Pipeline, Mereenie gas will
be able to access the east coast gas markets.
The Mereenie hydrocarbon accumulation is contained in an elongated 4-way dip anticline that has a length of 40 km and width of more than
5 km. Reservoirs comprise a series of thin stacked sandstones of the Pacoota Formation which have been the development focus, and in the
overlying Stairway Sandstone which has produced gas in several wells where it has been tested. The gas accumulation also has an oil rim.
The key development project underway is the Mereenie Expansion Project to increase the capacity of the facilities to deliver 44 TJ/d of sales
gas. The project scope includes installation of additional inlet separation, installation of a new Field Boost Compressor (“FBC”), restaging of
the existing FBCs and refurbishment of the ‘Plant 3’ liquids recovery plant. Front End Engineering Design (“FEED”) has been completed and a
Final Investment Decision (“FID”) was taken during the year to deliver the project in order to satisfy the IPL contract.
An appraisal well, West Mereenie 26, was drilled as a sub-horizontal well in the Stairway Sandstone. The well was designed to intersect an
area with a high density of natural fractures. The well was spud on 22 May 2018. Subsequent logging indicated the well did intersect
significant fractures, but the fractures were plugged by mineralisation that had occurred during geologic time. In its current configuration,
the well was unable to flow at commercial rates and was suspended on 6 July 2018 to enable the Company to potentially explore avenues to
enhance well productivity. Further development of the Stairway Sandstone remains under consideration via workovers of existing wells
and/or potential further drilling in the future.
Mereenie Eastern Satellite Station Processing Facilities
11
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Palm Valley Gas Field (OL3)
Northern Territory
(CTP—100% Interest)
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 at depths from 1,800 to 2,200 metres. The anticlinal structure is approximately 29 km in length
and 14 km in width.
In recent years, the field has been shut-in due to market limitations in the Northern Territory. The key development project underway is the
optimisation and restart of the field to deliver 15 TJ/d of sales gas into the broader gas market available via the NGP connection. The early
phases of this project determined that the current plant configuration is optimal and onsite activities are now underway to refurbish and
reinstate equipment to enable the field to be online prior to the commencement of the IPL contract.
Lease preparation is underway to drill an appraisal well, Palm Valley-13, to evaluate the Stairway, Pacoota Sandstone and Horn Valley
Siltstone reservoirs to connect as many as possible of the naturally occurring fractures. It is planned to drill the well as a high angle directional
well due to surface constraints. A well design and directional plan has been created that allows for a vertical surface hole to +/-1,000 m
followed by a directional build section to intersect the top of the reservoir. This section will be cased with a 7-inch liner. A 6-inch production
hole will be drilled horizontally within the Pacoota using direct circulation air/mist drilling techniques. The well spudded in August 2018.
Palm Valley-13 surface location and reservoir trajectory projection
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
12
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Dingo Gas Field (L7) and Dingo Pipeline (PL30)
Northern Territory
(CTP—100% Interest)
Gas was discovered at the Dingo field in 1985 in the Neoproterozoic lower Arumbera Sandstone. The structure is 11 km by 5.6 km, and the
productive reservoir is at a depth of approximately 3,000 metres subsurface.
The Dingo Gas Field Development, completed in April 2015, comprised the construction of wellhead facilities, gathering pipelines, gas
conditioning facilities, a 50 km gas pipeline to Brewer Estate in Alice Springs and custody transfer metering facilities. It was designed to
service a gas sale contract with Territory Generation.
Central conducted a review of geological and engineering data, and identified upside potential in the field. Several structural leads were
identified in the area immediately surrounding Dingo gas field, within Exploration Permit (EP) 82. These could provide interesting incremental
opportunities to Central’s 100% Dingo infrastructure. Further seismic is required to progress the targets to drillable status.
The field continued to supply the Owen Springs Power Station during the year. Progress continued on two minor projects to install a water
bath heater and a TEG unit to improve consistency of gas supply.
Surprise Oil Field (L6)
Northern Territory
(CTP—100% Interest)
Surprise West remained shut-in during the year. The well has been temporarily shut-in to gather pressure data to assess the re-charge
potential of the field. The fluid level is being monitored regularly. Further assessment of the pressure build-up, expected well deliverability
and production forecast will aid in determining the commerciality of bringing the well back on production.
EXPLORATION ASSETS
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, it is encouraging to note that 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. This has been augmented by outcrop
mapping to assist in structural definition between seismic lines. This updated mapping has been incorporated into a natural fracture
model which has defined areas with the greatest fracture density. The subsurface target and well trajectory have now been defined and the
surface location of the Ooraminna 3 has also been identified. The Ooraminna field has an inferred closure area of approximately 175 km2
and preliminary estimates of Original Gas In Place (“OGIP”) for the Pioneer Formation range from approximately 125 Bcf to 425 Bcf. Currently,
there are no resources certified at Ooraminna, however demonstrating increased productivity through drilling in areas of predicted increased
natural fracture density may lead to resource/reserves certification.
Tenure Update
Notices of Intent (“NOI”) to Grant for both retention licences were received from the Northern Territory Department of Primary Industry and
Resources (“DPIR”) on 1 August 2018. The Ooraminna 3 vertical appraisal well is being planned as part of the licence commitments. The well
design is to drill 12 ¼ inch top hole and set 9 5/8 inch surface casing at 400m–500m and then an 8 ½ inch hole will be drilled to total depth
to allow for a full reservoir evaluation and depth control. Once the data has been analysed a decision will be made as to further drilling or
completion options. The well is located to intersect the naturally occurring fractures to enhance the likelihood of the well’s success.
13
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Ooraminna 3 surface location and reservoir trajectory projection.
ATP909, ATP911 and ATP912
Southern Georgina Basin, Queensland
(CTP—100% interest)
The Department of Natural Resources and Mines (“DNRM”) has reviewed the Project Status submission from Central Petroleum. Central will
consult with DNRM in Q3, 2018 with regards to the best approach to secure Project Status for the Southern Georgina permits. Central has
also finalised lease arrangements for the Boulia warehouse and the consolidation of leases on which this facility sits.
Southern Amadeus Basin
Northern Territory
Various Exploration Permits (see table on page 92)
Santos Stage 2 Farm out – Southern Amadeus Basin, Northern Territory
In April 2018, Santos completed acquisition of 403 km of seismic data, infilling the previous 932 km of seismic acquired in 2016 and bringing
the total to 1,335 km, meeting the requirements of the Stage 2 Farm-in with Central. The additional seismic lines reduce dip line spacing over
the Dukas prospect to approximately 5 km between dip lines over the central prospect area, and approximately 10 km towards the flanks.
Processing of the acquired seismic data has commenced and is progressing.
In addition to seismic data coverage, Santos has also undertaken multi 1D modelling and gravity inversion studies over the Southern Amadeus
to further understand the structural history, magnitude of missing section and the implications on present-day structure. The structural
model continues to be refined with the addition of these new learnings.
The joint venture’s exploration endeavours on these permits focus on maturing large sub-salt leads. The primary reservoir objective is the
Heavitree Quartzite. Secondary reservoir objectives in the Neoproterozoic post-salt units include the Areyonga Formation and Pioneer
Sandstone, which are gas bearings in the Dingo and Ooraminna fields, respectively.
Central continues to monitor data in these permits, seeking to upgrade a variety of exploration play types and targets, which could be
prospective for hydrocarbons and/or helium.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
14
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Looking forward, Santos has requested a further 3-month extension of the Stage 2 end date to 3 October, 2018. Santos has also requested
an additional five month extension on the Stage 3 end date to 3 November 2019. Central is currently considering these requests.
Southern Amadeus Area
EP 82 (excluding EP 82 Sub-Blocks)
EP 105
EP 106 *
EP 112
EP 125
Total Santos Participating Interest after
completion of Stage 1
Total Santos Participating Interest after
completion of Stage 2
25%
25%
25%
25%
70%
40%
40%
40%
40%
70%
*
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.
Amadeus Basin (includes EP115 North Mereenie Block), Northern Territory
Central’s evaluation of inventory of leads and prospects is now completed. Play types and leads have been developed for the under-explored
section underlying the proven Larapintine system, which is believed to be prospective for gas.
Exploration Application Areas, Northern Territory
Amadeus, Pedirka and Wiso Basins — Various Areas (see table on page 92)
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 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, from this a proposed seismic grid has been created.
Wiso Basin depth to basement and application areas
15
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Reserves Information
Net proved (“1P”) gas reserves were 81.03 PJ and net proved (“1P”) oil reserves were 0.37 MMbbl at 30 June 2018. 1P gas reserves decreased
by 3.63 PJ while 1P oil reserves decreased 0.09 MMbbl, both through continued production.
Net proved plus probable (“2P”) gas reserves were 122.9 PJ and net proved plus probable (“2P”) oil reserves were 0.38 MMbbl at
30 June 2018.
All reserves and contingent resources volumes are based on independent expert Netherland, Sewell & Associates Inc (“NSAI”), reviewed and
reported volumes for the respective Petroleum Resources Management System compliant categories, dated 30 June 2015 for Palm Valley
and Dingo and 31 December 2015 for Mereenie oil and gas.
AGGREGATE RESERVES (Central Petroleum Share)
Oil
Proved reserves
Proved plus probable reserves
Contingent Resources 2C
Gas
Proved reserves
Proved plus probable reserves
Contingent Resources 2C
RESERVES PER ENTITY (Central Petroleum Share)
Unit
30/06/2018
Production for the period
01/07/2017 - 30/06/2018
01/07/2017
MMbbl
MMbbl
MMbbl
PJ
PJ
PJ
0.37
0.38
0.10
81.03
122.90
143.60
0.09
0.09
-
3.63
3.63
-
0.45
0.47
0.10
84.66
126.53
143.60
Unit
30/06/2018
Production for the period
01/07/2017 - 30/06/2018
30/06/2017
Mereenie, oil
Proved reserves
Proved plus probable reserves
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
MMbbl
MMbbl
MMbbl
PJ
PJ
PJ
PJ
PJ
PJ
PJ
PJ
PJ
0.37
0.38
0.10
56.23
69.30
91.20
16.69
22.59
29.70
8.11
31.01
22.7
0.09
0.09
-
2.83
2.83
-
0.01
0.01
-
0.79
0.79
-
0.45
0.47
0.10
59.06
72.14
91.20
16.70
22.60
29.70
8.89
31.79
22.7
Note: Estimates may not arithmetically balance due to rounding
QUALIFIED PETROLEUM RESERVES AND RESOURCES EVALUATOR
STATEMENT
The information contained in this report regarding the Central Petroleum reserves, contingent resources is based on, and fairly represents,
information and supporting documentation reviewed by Mr Richard Hamilton who is a full-time employee of Central Petroleum holding the
position of Subsurface Development Manager. Mr Hamilton holds a Master of Science degree, is a member 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.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
16
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
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 2018:
The Company made a fully underwritten institutional and sophisticated investor placement of 92,000,980 shares at an issue price
of $0.10 per share. In addition, the Company undertook a 5 for 12 traditional non-renounceable entitlement offer, issuing a further
180,499,020 shares also at $0.10 per share. These raised gross contributions of $27,250,000 before costs of $1,775,044.
The results and cash flows include revenue from the supply of gas under a GSA with EDL, which commenced in June 2017.
In addition to the above events that impacted the financial results for the year ended 30 June 2018, there were other events that will have
a forward impact on the state of affairs of the group.
The group entered into a new GSA with IPL during the year. Central will deliver at least 20 TJ/day of gas to IPL on an ex-field basis from
its Palm Valley and Mereenie fields. The gas will be delivered from the commencement of commercial operations of the NGP until
31 December 2019.
Additionally, a 50:50 joint venture arrangement for ATP 2031 in Queensland will be established with IPL, allowing the fast tracking of
developing this acreage. IPL will contribute up to $20 million for appraisal drilling costs during the initial exploration period with drilling
anticipated for 2019.
EVENTS SINCE THE END OF THE FINANCIAL YEAR
In July 2018, it was announced that Mr Richard Cottee will cease employment on 31 January 2019. Mr Leon Devaney is acting CEO in the
interim period.
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. As at 30 June 2018 the Consolidated Entity has not recognised any potential tax benefits from the
objections lodged.
In August 2018, Central was formally awarded ATP 2031 by the Queensland government.
GRR’s appeal opposing jurisdiction in the Supreme Court of Queensland was dismissed in the Company’s favour on 14 September 2018 (refer
to Note 29 (a) (iii) for further details).
On 26 September 2018, the Consolidated Entity’s debt facility with Macquarie Bank was extended by a further $7.5 million. Drawdowns
under this extension are at Central’s election and will be repayable in equal instalments from April to December 2019. As part of the
arrangement the Company will grant Macquarie Bank up to 22.5 million options with an exercise price of 14 cents and expiring
December 2019. Options will be granted in four equal tranches, the first on completion of the agreement and the remaining tranches as
funds drawn down under the facility reach certain thresholds.
On 27 September 2018, Central Petroleum Limited secured a $10 million facility with Hong Kong based investment company Long State
Investment Limited (“LSI”). Under the terms of the facility, Central Petroleum Limited may, at its discretion, issue shares to LSI at any
time over the next 24 months, up to a total of $10 million. Central Petroleum Limited may draw down up to $250,000 in any period of
5 trading days.
Shares issued to LSI will be priced at the lowest daily volume weighted average price (“VWAP”) of Central Petroleum Limited shares traded
on each of the 5 trading days which follow an advance notice by Central Petroleum Limited. A commission of 5% will be payable by
Central Petroleum Limited at the time of issue.
LSI may receive up to five million unlisted options through four separate tranches that are 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 Central is required to grant the options, will be
granted when the aggregate advances first exceeds $2.5 million, $5.0 million, and $7.5 million. The options have an exercise period of five
years from the date of issue. To date, Central has not utilised the ELOC and no options have been granted.
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.
17
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
INFORMATION ON DIRECTORS
Martin Kriewaldt, BA, LL.B (Hons 1st), University Medal, FAICD (Life), AICDQ Gold Medal
Independent Non-executive Chairman
Mr Kriewaldt was appointed a Director on 23 October 2017 and is a professional company Director with over 25 years’ experience.
He is a Life Fellow of the Australian Institute of Company Directors, serves on its Corporate Governance Committee, is Chair of an AICD Nexus
group and a Mentor in the AICD mentoring programme for women. He is a past President of the Institute of Company Directors (Queensland
Division) and has been awarded the AICD Gold Medal.
He was previously Chairman of Suncorp, Infratil Australia, Suncorp Property Trust and Thin Technologies, and was a Director of listed entities
including Campbell Brothers, Oil Search, Macarthur Coal, GWA, ImpediMed, BrisConnections and QDL. He has also been the Chairman or a
Director of a number of unlisted companies including Suncorp Building Society, Suncorp Finance, Hooker Corporation, Graham and Company
and Golding Contractors, as well as the national board of AICD.
In addition to these roles, he has chaired Board Sub-Committees for Audit, Risk, Environment, Remuneration, Investment, Corporate
Governance, Corporate Advisory and Nominations. He has also served as Deputy Chairman and Lead Independent Director. He was Chairman
of Opera Queensland and has also served on a number of other not-for-profit boards, including the Senate of the University of Queensland.
Previously, Mr Kriewaldt was a Partner of Allen & Hemsley (now Allens Linklaters) for 25 years specialising in banking and insurance, mining,
oil and gas and construction.
Richard Cottee BA, LLB (Hons)
Managing Director and Chief Executive Officer
Mr Cottee is a veteran of the oil and gas industry having started his commercial career with Santos Ltd in 1982. He was instrumental in the
development of the CSG industry having taken QGC from an early stage explorer, with a market capitalisation of approximately $30 million,
to a major gas supplier, which was sold to the BG Group for $5.7 billion six years later. He has extensive experience in the energy sector
generally, having been a CEO of a Queensland electricity generator (CS Energy) and of a subsidiary of NRG in Europe. In his career he has had
a role in the development of the industry in Queensland, South Australia and now the Northern Territory.
Mr Cottee joined Central Petroleum Limited in June 2012 as Managing Director and within the last three years has not been a Director of any
listed public company other than Austin Exploration Limited where he was a non-executive chairman until April 2015.
Wrixon F Gasteen BE (Mining) (Hons), QLD, MBA (Distinction), Geneva
Independent Non-executive Director
Mr Gasteen is a Director and co-founder of Ikon Corporate (Singapore), established in 2007 to provide corporate advisory, capital raising and
management consulting services. He has over 20 years’ experience in the mining, oil and gas, manufacturing and IT industries in Australia
and Asia.
Mr Gasteen has been CEO and Director of both listed and private companies in Australia, Asia, and the United States, and 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 technical team that
discovered and then developed the Boundary Hill Coal Mine in Central Queensland. He became its inaugural Mine Manager.
As CEO and Director of Hong Leong Asia Limited, listed on the Singapore Stock Exchange (SGX: HLA), he transformed the company through
acquisitions and organic growth from a loss making company with revenue of $300 million to a highly profitable conglomerate with
$2.2 billion in sales, 80% of which were in China and the remainder in SE Asia. During his term as CEO, he was presented with two successive
annual awards by the Securities Investors Association of Singapore, recognising Hong Leong Asia for its effort in demonstrating corporate
transparency. The BRW ranked Mr Gasteen No.3 in their Top 20 Australians Managing in Asia.
Mr Gasteen was also Director of Tasek Corporation (cement) listed on Kuala Lumpur Stock Exchange and Chairman and President of China
Yuchai International (diesel engines) listed on the New York Stock Exchange. He was appointed Non-Executive Director and Chairman of the
Audit Committee of ASX listed, Sino Australia Oil and Gas in March 2014, resigning in November 2015.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
18
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Dr Peter S Moore BSc (Hons 1), MBA, PhD, GAICD
Independent Non-executive Director
Dr Moore has more than thirty five years’ experience in the oil and gas business. His career includes roles with the Geological Survey of
Western Australia, Delhi Petroleum Pty Ltd, the exploration operator of the Cooper Basin consortium in South Australia and Queensland at
the time, Esso Australia Ltd, Exxon Exploration Company (Houston), Woodside Energy Ltd and Curtin University.
At Woodside, Peter held various roles including most recently as Executive Vice President Exploration. In this capacity he was a member of
Woodside’s Executive Committee and Opportunities Management Committee, a leader of its Crisis Management Team and Head of the
Geoscience function across the company. He was also a Director of a number of Woodside’s subsidiary companies.
Dr Moore is a Non-executive Director of Carnarvon Petroleum Limited and Beach Energy Limited. Until 31 March 2018, he was Professor and
Executive Director, Corporate Engagement at Curtin Business School. Dr Moore is Chair of ESWA Inc and a member of Curtin University’s
Faculty of Science and Engineering Advisory Council. Within the last three years, Dr Moore has not been a Director of any other listed
public company.
Sarah Ryan, PhD (Petroleum and Geophysics), BSc (Geophysics) (Hons 1), BSc (Geology)
Independent Non-executive Director
Dr Sarah Ryan was appointed a Director to the Central Board on 23 October 2017 and is a professional company Director and seasoned
professional with over 25 years’ local and international experience primarily in the oil and gas industry.
Dr Ryan currently holds non-executive directorships with Woodside Petroleum Ltd, MPC Kinetic Group, Akastor ASA (Oslo, Norway) and Viva
Energy. Previous positions include non-executive Director of Aker Solutions ASA (Oslo, Norway), Advisor-Energy to Earnest Partners (Atlanta,
USA) and Advisor to the Chairman of Saxo Bank A/S (Copenhagen, Denmark). She is also Chair of the Advisory Board of Unearthed Solutions.
During her career, Dr Ryan was Investment Director and Portfolio Manager at Earnest Partners, an Atlanta based investment management
firm, Chief Operating Officer of MTEM Ltd (Edinburgh, UK), General Manager of Asset Management for AGL (Sydney, Australia) and held
various technical, operational and executive positions with Schlumberger, both in Australia and overseas, during a 15 year tenure.
Dr Ryan holds a PhD in Petroleum Geology and Geophysics, a BSc (First Class Honours) in Geophysics, and a BSc in Geology. In addition, she
is a Fellow of the Australian Academy of Technology and Engineering, Fellow of the Institute of Energy, Member of the Australian Institute
of Company Directors, Member of Women Corporate Directors, and Member of Chief Executive Women.
Tim Woodall, BEcon, FCPA, GAICD
Independent Non-executive Director
Mr Woodall was appointed a Director to the Central Board on 20 December 2017 and has over 25 years’ experience in international M&A
and finance, specialising in the oil and gas sector.
His expertise includes being the founder and Managing Director of a boutique advisory firm, the CEO of a technical consulting firm and senior
roles in New York and London with global investment banks. Additionally, he has held senior executive positions with E&P companies in
Australia and the USA.
Mr Woodall has a Bachelor of Economics from the University of Adelaide, is a Fellow of the Australian Society of CPAs (FCPA) and a graduate
member of the Australian Institute of Company Directors (GAICD).
Mr Woodall is currently a Non-executive Director of FAR Limited.
19
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
COMPANY SECRETARIES
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.
Joseph P Morfea FAIM, GAICD
Mr Morfea has over 35 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 & Risk Committee
Remuneration &
Nominations Committee
Robert Hubbard3
Richard Cottee
Wrixon Gasteen
Martin Kriewaldt4
Peter Moore
Sarah Ryan4
Timothy Woodall5
Eligible1
Attended2
Eligible1
Attended2
Eligible1
Attended2
11
16
16
9
16
9
8
7
14
16
9
16
9
7
2
—
4
1
2
1
2
1
3
4
3
2
3
1
2
—
4
—
4
2
—
2
—
4
1
4
2
—
The number of meetings attended includes those attended by invitation
Robert Hubbard retired 14 May 2018
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 Martin Kriewaldt and Sarah Ryan were appointed Directors on 23 October 2017
5
Timothy Woodall was appointed Director on 20 December 2017
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
20
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
REALISED REMUNERATION OF DIRECTORS AND KEY MANAGEMENT
PERSONNEL FOR THE 2018 YEAR
The Directors consider the remuneration information contained within the tables presented in the statutory remuneration report (pages 23
to 32) may give a distorted view of the true remuneration realised by the directors and key management personnel for the 2018 year.
This is a voluntary disclosure and has been included to assist shareholders in forming an understanding of the cash and other benefits actually
received by Directors and key management personnel.
Non-Executive
Directors
Salary / fees
$
STIP
$
Termination
benefits
$
—
Superannuation
contributions
$
Non-
monetary
benefits1
$
912
—
—
—
—
—
912
—
—
—
—
—
—
—
Non-
monetary
benefits1
$
16,550
5,460
—
6,280
—
5,460
STIP
$
51,888
39,346
—
36,103
—
28,440
93,333
104,710
59,362
83,333
52,670
38,889
432,297
Salary / fees
$
587,491
499,778
29,167
501,212
50,000
412,561
Wrixon Gasteen
Robert Hubbard2
Martin Kriewaldt3
Peter Moore
Sarah Ryan3
Timothy Woodall4
Sub-total
Executive
Directors & Key
Management
Personnel
Richard Cottee
Leon Devaney
Ross Evans6
Michael Herrington
Robin Polson5
Daniel White
Sub-total
Total
Remuneration
Percentage
of TRP
%
Value of LTI
Grant that
Vested
$
Actual Total
Remuneration
Package
(TRP)
$
Amount
$
103,112
114,657
65,001
91,250
57,674
42,583
100%
100%
100%
100%
100%
100%
41,068
474,277
100%
—
—
—
—
—
—
—
103,112
114,657
65,001
91,250
57,674
42,583
474,277
Percentage
of TRP
%
Value of LTI
Grant that
Vested
$
Actual Total
Remuneration
Package
(TRP)
$
99%
98%
100%
97%
100%
97%
9,714
12,547
—
17,952
—
14,864
685,692
581,216
31,938
585,181
54,750
484,742
Amount
$
675,978
568,669
31,938
567,229
54,750
469,878
8,867
9,947
5,639
7,917
5,004
3,694
20,049
24,085
2,771
23,634
4,750
23,417
Superannuation
contributions
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2,080,209
155,777
33,750
2,512,506
155,777
34,662
98,706
2,368,442
98%
55,077
2,423,519
139,774
2,842,719
98%
55,077
2,897,796
Fringe benefits include loan fringe benefits relating to deferred Director option fees and employee car parking fringe benefits
Robert Hubbard retired 14 May 2018
1
2
3 Martin Kriewaldt and Sarah Ryan were appointed Directors 23 October 2017
4
5
6
Timothy Woodall was appointed Director 20 December 2017
Robin Polson commenced 1 May 2018
Ross Evans commenced 1 June 2018
ENVIRONMENTAL REGULATION
The Consolidated Entity is subject to significant environmental regulation.
The Consolidated Entity aims to ensure the appropriate standard of environmental care is achieved and, in doing so, that it is aware of and
is in compliance with all environmental legislation. The Directors of the Company and the Consolidated Entity are not aware of any breach
of environmental legislation for the year under review.
INSURANCE OF DIRECTORS AND OFFICERS
During the financial year, the Group paid premiums to insure Directors and officers of the Group. The contracts include a prohibition on
disclosure of the premium paid and nature of the liabilities covered under the policy.
NUMBER OF EMPLOYEES
The Company had 89 employees at 30 June 2018 (83 at 30 June 2017).
21
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
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
Other tax related services
(ii) Other services
Technical accounting advice on major transactions
Employee related services
2018
$
8,160
26,259
34,419
—
—
—
2017
$
17,615
19,622
37,237
—
—
—
Total remuneration for non-audit services
34,419
37,237
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 33.
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.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
22
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
REMUNERATION REPORT (AUDITED)
This remuneration report for the year ended 30 June 2018 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
Directors and Key Management Personnel (“KMP”)
Remuneration Overview
Remuneration Policy
Remuneration Consultants
Long Term Incentive Plan (“LTIP”)
Short Term Incentive Plan (“STIP”)
Remuneration Details
Executive Service Agreements
Non-Executive Director Fee Arrangements
A. Directors and Key Management Personnel
The Directors and key management personnel of the Consolidated Entity during the year and up to signing date of the annual report were:
Directors
Robert Hubbard
Non-executive Chairman (retired 14 May 2018)
Martin Kriewaldt
Non-executive chairman (appointed 23 October 2017)
Richard Cottee
Managing Director and Chief Executive Officer (to 30 July 2018)
Wrixon Gasteen
Non-executive Director
Peter Moore
Sarah Ryan
Non-executive Director
Non-executive Director (appointed 23 October 2017)
Timothy Woodall
Non-executive Director (appointed 20 December 2017)
Other Key Management Personnel
Leon Devaney
Ross Evans
Chief Financial Officer and Acting Chief Executive Officer (from 31 July 2018)
Chief Operations Officer (commenced 1 June 2018)
Michael Herrington
President - Operations and Chief Development Officer
Robin Polson
Daniel White
Chief Commercial Officer (commenced 1 May 2018)
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.
23
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Financial Year 2018, summary of fixed and variable remuneration outcomes
Inflation Salary average
increases of 1.9%
Where appropriate, a pay rise was awarded to address inflation and on account of a change in role,
responsibilities or other extenuating circumstances.
STIP
LTIP Vesting
The Company’s Short Term Incentive Plan was scheduled and paid during the first quarter of fiscal
year 2019.
Awards vested under the Long Term Incentive Plan for the three year period ending 30 June 2017 during
fiscal year 2018.
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 have a particular focus 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”).
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. In this period the Remuneration Committee appointed Guerdon Associates to undertake certain work. The report
provided contained no recommendations as to the elements or amounts of Key Management Personnel remuneration.
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 2018, 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. Whilst some of the current non-executive Directors benefit from options
issued in accordance with shareholder approval in 2012, no further issues have been made and it is not intended that non-executive
Directors will participate in either the LTIP or STIP in the future.
Executives, including Executive Directors:
1. Annual salary and non-monetary benefits including statutory superannuation;
2. Participation in a Short Term Incentive Plan;
3. Participation in an Long Term Incentive Plan (Performance Rights scheme); and
4. There is 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 will be a major component of executive incentives and, in developing the LTIP, the Board of Central has focused on creating strong
linkages between shareholder value as measured by shareholder returns and executive remuneration. Consequently, vesting conditions have
been divided equally between relative shareholder return and absolute shareholder return. In doing this the Board have 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%.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
24
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Key terms and vesting conditions
On 26 November 2014 and subsequently on 2 November 2015, shareholders approved the Company to implement a share based LTIP to
incentivise eligible employees (Non-Executive Directors are not eligible to participate in the LTIP). The delivery instrument is performance
rights, effective for years commencing 1 July 2014 onwards.
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
Relative TSR – E&P2
(50% weighting)
Company's TSR relative to a specific group of exploration and
production companies (determined by the Board within its
discretion) calculated as at vesting date.
1
2
Total shareholder return (i.e. growth in share price plus dividends reinvested)
Exploration and Production
HURDLE BANDING
Company’s Absolute TSR
over 3 years
Below 10% pa
10% to <15% pa
15% to <20% pa
20% to <25% pa
25% pa plus
VESTING
PERCENTAGE
Share Rights Vesting
0%
25%
50%
75%
100%
Company’s Relative TSR
Below 51st percentile
51st percentile
52nd to 75th percentile
76th percentile and above
Share Rights Vesting
0%
50%
51% to 99%
100%
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 vested 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.
The personal and corporate key performance indicators and other targets for the Managing Director and other employees are reviewed at
least annually to ensure they remain relevant and appropriate. These may be varied to ensure alignment of executive performance and
achievement consistent with the Company’s goals and objectives.
Employees must be employed by the Company at the end of the Performance Period in order for the Performance Rights to vest. The number
of shares that vest 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 Central
Petroleum $1,000.00 Exempt Plan.
25
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Conditions of the Central Petroleum $1,000.00 Exempt Plan include:
a.
Share Rights can only be dealt with the earlier of three years or on termination of employment; and
b. No performance conditions apply.
Rights Vesting during the Financial Year
During the 2018 financial year 50% of Share Rights issued for the Plan Year commencing 1 July 2014 vested. The vesting percentage was
determined on the basis of achieving 100% vesting for Relative TSR and 0% vesting for Absolute TSR, giving an average vesting of 50%.
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 in 2017/18.
Key terms and conditions
The 2017/2018 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 KPIs
Departmental KPIs
Individual KPIs
PERCENT ALLOCATION OF STIP
Executive
30%
10%
40%
20%
All Other Employees
30%
10%
30%
30%
1.
2.
3.
4.
Corporate KPIs represent an overall 30% of the STIP
Safety and Environment KPIs represent 10% of the STIP
Departmental KPIs represent a spread of 40% for executives and 30% for all other employees
Individual KPIs represent a spread of 20% for executives and 30% for all other employees
The 2017/2018 Plan Year 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 will form the basis of the recommendation to the Board who will decide the amount.
This percentage will be annually reviewed by the Board through the Remuneration and Nominations Committee.
At the Board’s discretion, a combination of cash and company securities, or cash or company securities, may be paid as the benefit in the
2017/2018 Plan Year STIP.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
26
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Corporate KPIs included:
OBJECTIVE
Drilling
Approval & funding of facility upgrades & commercial
restructuring – targeting increase sales by NGP
becoming operational
Budget (original submission approved by the Board,
unless amended due to a Board approved change
of scope)
WEIGHTING
100%
75%
50%
25%
25%
Successful completion of
3 wells
Successful completion of
2 wells
Successful completion of
1 well
25TJ p/day
20TJ p/day
15TJ p/day
25%
0% (of budget)
5% (of budget)
10% (of budget)
Pipeline Tariffs *
25%
$2.00 per GJ below
reference
$1.50 per GJ below
reference
$0.75 cents per GJ below
reference
* Substantial progress towards the introduction of economic regulation having the intended results for the Company.
Safety and Environment KPIs included:
OBJECTIVE
WEIGHTING
100%
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%
Zero
Zero
Zero
75%
1 which has been
remedied
1 of less than 2 days
N/A
0%
Defaulted
Defaulted
Defaulted
Maintain at least 50% local employment and 25% Indigenous employment in
Alice Springs
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 the following tables. Details of realised remuneration appear on page 21.
27
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Table 1: Remuneration of Directors and Key Management Personnel
SHORT-TERM
POST-EMPLOYMENT
LONG-TERM
BENEFITS
Salary / fees
$
Cash STI8
$
Non-monetary
benefits1
$
Superannuation
contributions
$
Termination
Benefits
$
LSL
$
SHARE-BASED
PAYMENTS
(At Risk)
Options &
Rights9
$
Non-Executive Directors
Wrixon Gasteen
Robert Hubbard2
Martin Kriewaldt3
Peter Moore
Sarah Ryan3
J Thomas Wilson4
Timothy Woodall5
Sub-total
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
93,333
75,000
104,710
110,000
59,362
—
83,333
80,000
52,670
—
—
2,837
38,889
—
432,297
267,837
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
912
15,510
—
—
—
—
—
—
—
—
—
—
—
—
912
15,510
Executive Directors and Other Key Management Personnel
Richard Cottee
Leon Devaney
Ross Evans7
Michael Herrington
Robin Polson6
Daniel White
Sub-total
Total Remuneration
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
565,954
607,706
517,512
412,005
31,411
—
523,557
474,166
53,846
—
384,336
407,527
2,076,616
1,901,404
2,508,913
2,169,241
—
51,888
—
39,346
—
—
—
36,103
—
—
17,900
28,440
17,900
155,777
17,900
155,777
16,550
7,738
5,460
4,305
—
—
6,280
17,577
—
—
5,460
3,618
33,750
33,238
34,662
48,748
8,867
7,125
9,947
10,450
5,639
—
7,917
7,600
5,004
—
—
—
3,694
—
41,068
25,175
20,049
19,616
24,085
28,163
2,771
—
23,634
36,109
4,750
—
23,417
33,078
98,706
116,966
139,774
142,141
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
9,451
—
—
—
—
—
—
—
—
—
—
—
—
—
9,451
16,988
18,970
19,483
9,082
316
—
13,696
11,006
543
—
8,730
7,525
59,756
46,583
59,756
46,583
713,704
1,445,743
110,740
91,951
—
—
149,623
139,875
—
—
123,802
111,084
1,097,869
1,788,653
1,097,869
1,798,104
Value of
Options &
Rights as
Proportion of
Remuneration
%
0%
9%
0%
0%
0%
—
0%
0%
0%
—
0%
0%
0%
—
0%
3%
54%
67%
16%
16%
0%
N/A
21%
20%
0%
N/A
22%
19%
32%
44%
28%
41%
Total
$
103,112
107,086
114,657
120,450
65,001
—
91,250
87,600
57,674
—
—
2,837
42,583
—
474,277
317,973
1,333,245
2,151,661
677,280
584,852
34,498
—
716,790
714,836
59,139
—
563,645
591,272
3,384,597
4,042,621
3,858,874
4,360,594
Robert Hubbard retired 14 May 2018
1 Non-monetary benefits includes fringe benefits tax
2
3 Martin Kriewaldt and Sarah Ryan were appointed Directors effective 23 October 2017
4
5
6
7
8
J Thomas Wilson resigned as Director 15 July 2016
Timothy Woodall was appointed Director effective 20 December 2017
Robin Polson commenced 1 May 2018
Ross Evans commenced 1 June 2018
Short Term Incentives are unpaid at the end of the financial year. Amounts are shown in respect of the performance year to which they relate.
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 with 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.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
28
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
The following factors and assumptions were used in determining the fair value of rights granted to key management personnel during the
2018 year:
GRANT DATE
EXPIRY DATE
01 Sep 2017
3 Oct 2022
29 Nov 2017
18 Dec 2022
27 Jun 2018
28 Jun 2023
FAIR VALUE
PER RIGHT
EXERCISE PRICE
PRICE OF SHARES
AT GRANT DATE
ESTIMATED
VOLATILITY
RISK FREE
INTEREST RATE DIVIDEND YIELD
$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%
The following factors and assumptions were used in determining the fair value of share rights granted during the 2017 year:
GRANT DATE
EXPIRY DATE
20 Oct 2016
16 Nov 2016
16 Nov 2016
8 Dec 2022
8 Dec 2022
8 Dec 2022
FAIR VALUE PER
RIGHT
EXERCISE PRICE
PRICE OF SHARES
AT GRANT DATE
ESTIMATED
VOLATILITY
RISK FREE
INTEREST RATE DIVIDEND YIELD
$0.106
$0.072
$0.151
Nil
Nil
Nil
$0.135
$0.185
$0.185
86%
92%
92%
1.86%
2.05%
2.05%
0.00%
0.00%
0.00%
Table 2: Share Based Compensation – Share Rights Granted during the Year
Richard Cottee
Leon Devaney
Ross Evans2
Michael Herrington
Robin Polson1
Daniel White
NUMBER OF
RIGHTS GRANTED
1,835,910
18,319
3,202,983
754,705
26,714
135,920
1,311,533
—
—
892,835
38,222
1,557,666
398,571
—
—
736,319
31,647
1,289,666
GRANT DATE
29 Nov 17
29 Nov 17
16 Nov 16
01 Sep 17
29 Sep 17
27 Jun 18
20 Oct 16
—
—
01 Sep 17
29 Sep 17
16 Nov 16
16 Nov 16
—
—
01 Sep 17
29 Sep 17
16 Nov 16
2018
2018
2017
2018
2018
2018
2017
2018
2017
2018
2018
2017
2017
2018
2017
2018
2018
2017
AVERAGE
FAIR VALUE AT
GRANT DATE
$0.055
$0.084
$0.151
$0.081
$0.097
$0.102
$0.106
—
—
$0.081
$0.097
$0.151
$0.072
—
—
$0.081
$0.097
$0.151
AVERAGE EXERCISE
PRICE PER RIGHT
$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
EXPIRY DATE
18 Dec 22
18 Dec 22
08 Dec 22
03 Oct 22
22 Sep 20
28 Jun 23
08 Dec 22
—
—
03 Oct 22
22 Sep 20
08 Dec 22
08 Dec 22
—
—
03 Oct 22
22 Sep 20
08 Dec 22
1 Robin Polson commenced 1 May 2018
2 Ross Evans commenced 1 June 2018
Table 3: Share Based Compensation – Share Rights Vested during the Year
Richard Cottee
Leon Devaney
Ross Evans4
Michael Herrington
Robin Polson3
Daniel White
MAXIMUM NUMBER
OF RIGHTS ELIGIBLE
FOR VESTING
209,350
—
305,285
—
—
—
436,793
—
—
—
361,647
—
LONG TERM
INCENTIVE PLAN
YEAR COMMENCING VESTING DATE
15 Dec 17
—
31 Oct 17
—
—
—
31 Oct 17
—
—
—
31 Oct 17
—
01 Jul 14
—
01 Jul 14
—
—
—
01 Jul 14
—
—
—
01 Jul 14
—
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
NUMBER OF RIGHTS
VESTED1
104,675
—
152,642
—
—
—
218,396
—
—
—
180,823
—
PROPORTION OF
RIGHTS VESTED2
50%
—
50%
—
—
—
50%
—
—
—
50%
—
The proportion of rights vested represents the proportion of the maximum number of rights that were eligible for vesting during the financial year
1 The number of rights that vested during the year relates to rights granted in prior financial years under the Long Term Incentive Plan
2
3 Robin Polson commenced 1 May 2018
4
Ross Evans commenced 1 June 2018
29
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Table 4: Shareholdings of Key Management Personnel
HELD AT
BEGINNING
OF YEAR
HELD AT
DATE OF
APPOINTMENT
SPP & ON
MARKET
PURCHASE
RECEIVED ON
EXERCISE OF
OPTIONS/RIGHTS
NET CHANGE
OTHER
HELD AT
DATE OF
DEPARTURE
HELD AT END
OF YEAR
Non-Executive Directors
Wrixon Gasteen
Robert Hubbard1
Martin Kriewaldt2
Peter Moore
Sarah Ryan2
Timothy Woodall3
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
136,473
136,473
298,947
298,947
N/A
N/A
—
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
200,000
N/A
—
—
—
N/A
1,000,000
N/A
156,864
—
365,667
—
900,000
N/A
265,000
—
105,000
N/A
500,000
N/A
Executive Directors and Other Key Management Personnel
Richard Cottee
Leon Devaney
Ross Evans6
Michael Herrington
Robin Polson5
Daniel White
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
571,829
632,438
210,000
210,000
N/A
N/A
250,000
250,000
N/A
N/A
288,000
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
—
—
N/A
104,168
—
—
N/A
160,000
—
—
—
—
—
—
N/A
—
—
—
N/A
—
N/A
104,675
—
152,642
—
—
N/A
218,396
—
—
N/A
180,823
—
—
—
—
—
N/A
—
—
—
N/A
—
N/A
(3,500)4
(60,609)4
—
—
—
N/A
—
—
—
N/A
—
—
N/A
N/A
664,614
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
293,337
136,473
N/A
298,947
1,100,000
N/A
265,000
—
105,000
N/A
1,500,000
N/A
889,933
571,829
629,022
210,000
—
N/A
572,564
250,000
—
N/A
628,823
288,000
Robert Hubbard retired 14 May 2018
1
2 Martin Kriewaldt and Sarah Ryan were appointed Directors 23 October 2017
3
4
Timothy Woodall was appointed Director 20 December 2017
Shares held by members of Mr Cottee’s family no longer considered under his control have been removed from this table. No shares were sold by Mr Cottee during
the 2017 year
Robin Polson commenced 1 May 2018
Ross Evans commenced 1 June 2018
5
6
Table 5: Option Holdings of Key Management Personnel
HELD AT
BEGINNING
OF YEAR
OPTIONS
EXERCISED
GRANTED AS
REMUNERATION
EXPIRED
HELD AT DATE OF
DEPARTURE
HELD AT
END OF YEAR
Non-Executive Directors
Wrixon Gasteen
2018
2017
—
666,666
Executive Directors and Other Key Management Personnel
Richard Cottee
Michael Herrington
Daniel White
Leon Devaney
2018
2017
2018
2017
2018
2017
2018
2017
24,900,773
24,900,773
—
1,950,000
—
760,000
—
504,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(666,666)
(24,900,773)
—
—
(1,950,000)
—
(760,000)
—
(504,000)
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
—
—
—
24,900,773
—
—
—
—
—
—
No employee options were outstanding at the end of the financial year and no options were exercised during the current or prior
financial year.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
30
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 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.
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:
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
NUMBER OF
RIGHTS HELD AT
END OF YEAR
(UNVESTED)
Executive Directors and Other Key Management Personnel
Richard Cottee
Leon Devaney
Michael Herrington
Daniel White
2018
2017
2018
2017
2018
2017
2018
2017
5,307,887
2,104,904
2,373,104
1,061,571
2,886,237
930,000
2,389,666
1,100,000
1,854,229
3,202,983
917,339
1,311,533
931,057
1,956,237
767,966
1,289,666
(104,675)
—
(152,643)
—
(218,397)
—
(180,824)
—
(104,675)
—
(152,642)
—
(218,396)
—
(180,823)
—
6,952,766
5,307,887
2,985,158
2,373,104
3,380,501
2,886,237
2,795,985
2,389,666
G. Executive Service Agreements
The details of service agreements of the key management personnel of the Consolidated Entity are as follows:
Richard Cottee, Managing Director and Chief Executive Officer
As announced, Mr Cottee’s employment will end on the 31st January 2019.
Mr Cottee’s base salary is presently $598,654 per annum. In addition, superannuation at 9.5% subject to the statutory limit
is applicable.
Leon Devaney, Chief Financial Officer and Acting Chief Executive Officer
The term of the agreement expires 1st July 2022.
Mr Devaney’s base salary is presently $505,000 per annum. In addition, superannuation at 9.5% is applicable. The salary is
reviewed annually.
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 (commenced 1 June 2018)
The term of the agreement expires 1 June 2021.
Mr Evan’s base salary is presently $356,650 per annum. In addition, superannuation at 9.5% is applicable. The salary is
reviewed annually.
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.
31
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2018
Mike Herrington, President – Operations and Chief Development Officer
The term of the agreement expires 29 January 2019.
Mr Herrington’s base salary is presently $485,226 per annum. In addition, superannuation at 9.5% is applicable. The salary is
reviewed annually.
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.
Robin Polson, Chief Commercial Officer (Commenced 1 May 2018)
The term of the agreement expires 1 May 2021.
Mr Polson’s base salary is presently $300,000 per annum. In addition, superannuation at 9.5% is applicable. The salary is
reviewed annually.
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 base salary is presently $400,164 per annum. In addition, superannuation at 9.5% is applicable. The salary is
reviewed annually.
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.
H. 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 2018.
BOARD FEES (PER ANNUM)
Chairman
Non-Executive Director
COMMITTEE FEES (PER ANNUM)
Audit
Risk
Remuneration &
Nominations
Chair
Member
Chair
Member
Chair
Member
$130,000.00
$70,000.00
$10,000.00
$5,000.00
$10,000.00
$ Nil
$10,000.00
$5,000.00
The directors also receive superannuation benefits.
Signed in accordance with a resolution of the directors:
Martin Kriewaldt
Chairman
Brisbane
28 September 2018
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
32
AUDITOR’S INDEPENDENCE DECLARATION
30 JUNE 2018
33
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
CORPORATE GOVERNANCE STATEMENT
Central Petroleum Limited and the 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 2018 Corporate Governance Statement is dated as at 30 June 2018 and reflects the corporate governance practices in place throughout
the 2018 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/.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
34
FINANCIAL REPORT
CONTENTS
Financial Statements
Consolidated Statement of Profit or Loss and Other Comprehensive Income .................. 36
Consolidated Statement of Financial Position ................................................................... 37
Consolidated Statement of Changes in Equity ................................................................... 38
Consolidated Statement of Cash Flows .............................................................................. 39
Notes to the Consolidated Financial Statements .............................................................................. 40
Directors’ Declaration ........................................................................................................................ 84
Independent Auditor’s Report to the Members ................................................................................ 85
ASX Additional Information ............................................................................................................... 90
Interests in Petroleum Permits and Pipeline Licences ...................................................................... 92
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 32. These pages are not part of these financial statements.
The financial statements were authorised for issue by the Directors on 28 September 2018. 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.
35
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND
OTHER COMPREHENSIVE INCOME
FOR THE YEAR ENDED 30 JUNE 2018
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
Revaluation of financial liabilities
Impairment expense
Loss before income tax
Income tax credit
Loss for the year
NOTE
2018
$
2017
$
23
34,939,194
(18,704,042)
24,794,145
(15,701,690)
16,235,152
9,092,455
2
31(d)
3(a)
3(a)
3(a)
3(a)
1,055,184
(1,622,329)
(595,925)
(8,033,092)
(4,061,759)
(8,790,052)
(7,848,877)
(414,431)
—
3,114,038
(2,251,024)
(1,946,659)
(7,780,576)
(5,658,990)
(1,901,382)
(7,812,071)
(9,493,259)
(89,013)
(14,076,129)
(24,726,481)
4
—
—
(14,076,129)
(24,726,481)
Other comprehensive loss for the year, net of tax
—
—
Total comprehensive loss for the year
(14,076,129)
(24,726,481)
Total comprehensive loss attributable to members of the parent entity
(14,076,129)
(24,726,481)
Basic and diluted loss per share (cents)
22
(2.13)
(5.71)
The accompanying notes form part of these financial statements.
2016 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
36
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
AS AT 30 JUNE 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
NOTE
2018
$
2017
$
6
7
8
12
9
10
11
12
13
14
15
16
18
17
15
16
18
17
27,222,845
6,631,642
3,575,480
2,333,333
5,478,140
4,996,216
3,273,014
—
39,763,300
13,747,370
103,853,369
8,898,767
156,017
2,535,915
3,906,270
106,816,359
8,898,767
82,157
2,501,947
3,906,270
119,350,338
122,205,500
159,113,638
135,952,870
8,113,667
7,283,068
3,727,338
38,600
3,406,515
3,239,168
2,714,334
3,859,747
38,600
3,161,454
22,569,188
13,013,303
13,678,980
74,599,221
15,362,506
25,840,435
5,283,741
78,310,007
21,914,537
23,389,129
129,481,142
128,897,414
152,050,330
141,910,717
7,063,308
(5,957,847)
19
20
21
197,776,487
23,463,784
(214,176,963)
172,301,532
21,841,455
(200,100,834)
7,063,308
(5,957,847)
The accompanying notes form part of these financial statements.
37
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEAR ENDED 30 JUNE 2018
CONTRIBUTED
EQUITY
$
RESERVES
$
ACCUMULATED
LOSSES
$
TOTAL
$
Balance at 1 July 2016
172,301,532
19,590,431
(175,374,353)
16,517,610
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
Share and option issues
Share issue costs
—
—
—
—
—
—
—
—
—
—
—
(24,726,481)
—
(24,726,481)
—
(24,726,481)
(24,726,481)
2,251,024
—
—
—
2,251,024
—
—
—
—
—
2,251,024
—
—
—
2,251,024
Balance at 30 June 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
—
—
—
—
—
—
(14,076,129)
—
(14,076,129)
—
(14,076,129)
(14,076,129)
Transactions with owners in their
capacity as owners
Share based payments
Options issued for financing
Share and option issues
Share issue costs
—
—
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
The accompanying notes form part of these financial statements.
The accompanying notes form part of these financial statements.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
38
CONSOLIDATED STATEMENT OF CASH FLOW
FOR THE YEAR ENDED 30 JUNE 2018
Cash flows from operating activities
Receipts from customers
Interest received
Other income
Interest and borrowing costs
Payments to suppliers and employees (inclusive of GST)
NOTE
2018
$
2017
$
39,285,428
494,077
25,660
(5,987,298)
(28,644,637)
27,628,945
165,581
667,355
(6,347,719)
(22,348,163)
Net cash inflow/(outflow) from operating activities
27
5,173,230
(234,001)
Cash flows from investing activities
Payments for property, plant and equipment
Payments for interest in Mereenie Joint Venture
Proceeds from sale of property, plant and equipment
Proceeds and deposits for the disposal of exploration permits
(Acquisition)/Redemption of security deposits and bonds
(2,999,815)
—
33,636
430,000
(2,367,302)
(1,297,122)
(3,342,446)
99,591
—
(863,581)
Net cash outflow from investing activities
(4,903,481)
(5,403,558)
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
Net cash inflow/(outflow) from financing activities
27,250,000
(1,775,044)
—
(4,000,000)
—
—
—
(4,000,000)
21,474,956
(4,000,000)
28
Net increase/(decrease) in cash and cash equivalents
21,744,705
(9,637,559)
Cash and cash equivalents at the beginning of the financial year
5,478,140
15,115,699
Cash and cash equivalents at the end of the financial year
6
27,222,845
5,478,140
The accompanying notes form part of these financial statements.
39
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
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. 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 $14,076,129, a net positive cash flow from operations of $5,173,230 and an overall net asset
position of $7,063,308. The Group continually monitors its cash flow requirements to ensure it has sufficient funds to meet its contractual
commitments and adjust its spending, particularly with respect to discretionary exploration activity and corporate overhead, accordingly.
Supported by the cash assets at 30 June 2018 of $27,222,845, and its cash flow forecasts, 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. The Company has
$12.5 million undrawn debt available under the Macquarie debt facility (refer Notes 32 (e) and 34) and a further $5 million available under a
partial pre-payment in relation to the recently announced IPL GSA. In addition the Company has signed a $10 million Equity Line of Credit
with Long State Investment Limited (refer Note 34).
The net asset position of $7,063,308 includes financial liabilities of $15,362,506 and deferred revenue liabilities of $7,865,982 recorded in
respect of the Macquarie Bank Limited Gas Sale and Pre-payment Agreement entered into in May 2016 as discussed in Note 3(b). At the time
of settlement over the three year term, the liability will be satisfied by the physical delivery of gas from existing 1P reserves through 2019,
after which it may be satisfied at the election of Macquarie by either the physical delivery of gas or paid out of the proceeds of the sale of
gas contracted under the EDL GSA for which no asset has been recognised in the accounts.
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 2017 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.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 40
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
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 their fair value models, and the variable elements in these models, used in determining
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, and temporary differences arising from the Petroleum Resource Rent Tax (Imposition – General) Act 2011, 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
Subsidiaries
(i)
The consolidated financial statements incorporate the assets and liabilities of all subsidiaries of Central Petroleum Limited (“the Company”
or “Parent Entity”) as at 30 June and the results of all subsidiaries for the year then ended. Central Petroleum Limited and its subsidiaries
together are referred to in this financial report as “the Group” or “the Consolidated Entity”.
Subsidiaries are all entities (including structured entities) over which the group has control. The group controls an entity when the group is
exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power
to direct the activities of the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the group.
They are deconsolidated from the date that control ceases. The acquisition method is used to account for business combinations by
the Group.
41
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(b) Principles of Consolidation (continued)
(i)
Subsidiaries (continued)
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 33.
(c) Segment Reporting
Operating segments are reported 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
Functional and Presentation Currency
(i)
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 is recognised and measured at the fair value of the consideration received or receivable, net of goods and services tax, to the extent
it is probable that the economic benefits will flow to the Group and the revenue can be reliably measured. The following specific recognition
criteria must also be met before revenue is recognised:
Sale of Oil and Gas / Deferred Revenue
(i)
Revenue is recognised when the significant risks and rewards of ownership of the product have passed to the buyer and the amount of
revenue can be measured reliably. Risks and rewards are considered to have passed to the buyer at the time of delivery of the product to
the customer. Revenue from take or pay contracts is recognised in earnings when the product is taken by the customer or their right to take
product expires. It is recorded as liability (deferred revenue) when it has not been taken and a right to take it in future still exists.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
42
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(e) Revenue Recognition (continued)
Interest Income
(ii)
Interest revenue is recognised on a time proportionate basis that takes into account the effective yield on the financial assets.
(f) Government Grants
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.
(g) Income Tax
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 and to unused tax losses.
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.
Deferred tax is provided in full, using the liability method, on temporary differences arising between the tax bases of assets and liabilities
and their carrying amounts in the consolidated financial statements. Deferred tax liabilities are not recognised if they arise from the initial
recognition of goodwill. Deferred tax is also not accounted for if it arises from initial recognition of an asset or liability in a transaction other
than a business combination that, at the time of the transaction, affects neither accounting nor taxable profit or loss. Deferred income tax is
determined using tax rates (and laws) that have been enacted or substantially enacted by the end of the reporting period and are expected
to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled.
Deferred tax assets 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.
Deferred tax liabilities and assets are not recognised for temporary differences between the carrying amount and tax bases of investments
in foreign operations where the Group is able to control the timing of the reversal of the temporary differences and it is probable that the
differences will not reverse in the foreseeable future.
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.
Central Petroleum Limited and its wholly-owned Australian controlled entities have implemented the tax consolidation legislation. As a
consequence, these entities are taxed as a single entity and the deferred tax assets and liabilities of these entities are set off in the
consolidated financial statements. Current and deferred tax is recognised in profit or loss, except to the extent that it relates to items
recognised in other comprehensive income or directly in equity. In this case, the tax is also recognised in other comprehensive income or
directly in equity, respectively.
(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 30(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.
43
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(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 fair value and subsequently measured at amortised cost using the effective interest method, less
provision for impairment. Trade receivables are generally due for settlement within 90 days. They are presented as current assets unless
collection is not expected for more than 12-months after the reporting date.
Collectability of trade receivables is reviewed on an ongoing basis. Debts which are known to be uncollectible are written off by reducing the
carrying amount directly. An allowance account (provision for impairment of trade receivables) is used when there is objective evidence that
the Group will not be able to collect all amounts due according to the original terms of the receivables. Significant financial difficulties of the
debtor, probability that the debtor will enter bankruptcy or financial reorganisation, and default or delinquency in payments (more than
90 days overdue) are considered indicators that the trade receivable is impaired. The amount of the impairment allowance is the difference
between the asset's carrying amount and the present value of estimated future cash flows, discounted at the original effective interest rate.
Cash flows relating to short-term receivables are not discounted if the effect of discounting is immaterial.
The amount of the impairment loss is recognised in profit or loss within other expenses. When a trade receivable for which an impairment
allowance had been recognised becomes uncollectible in a subsequent period, it is written off against the allowance account. Subsequent
recoveries of amounts previously written off are credited against other expenses in profit or loss.
(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 loans and receivables. 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. Loans and receivables are included in trade and other receivables (Note 7)
and other financial assets (Note 12) 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.
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.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
44
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(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
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 and subsurface development expenditure (“subsurface assets”) 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.
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
45
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(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.
(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.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
46
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(s) Provisions (continued)
(iii) Other (continued)
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 interest expense.
(t) Employee Benefits
Short-term Obligations
(i)
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.
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 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 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.
47
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(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.
(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.
Investments in Subsidiaries, Associates and Joint Venture Entities
(i)
Investments in subsidiaries, associates and joint venture entities are accounted for at cost in the financial statements of Central
Petroleum Limited.
(ii) Tax Consolidation Legislation
Central Petroleum Limited and its wholly-owned Australian controlled entities have implemented the income tax consolidation legislation.
The head entity, Central Petroleum Limited, and the controlled entities in the income tax consolidated Group account for their own current
and deferred tax amounts where recognition of such is permitted under accounting standards. These tax amounts are measured as if each
entity in the tax consolidated Group continues to be a standalone taxpayer in its own right.
In addition to its own current and deferred tax amounts, Central Petroleum Limited also recognises the current tax liabilities or assets
and the deferred tax assets arising from unused tax losses from controlled entities, where permitted to recognise such assets under
accounting standards.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
48
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(z) Business Combinations
Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the
consideration transferred, measured at acquisition date fair value and the amount of any non-controlling interest in the acquiree. For each
business combination, the Group elects whether it measures the non-controlling interest in the acquiree at fair value or at the proportionate
share of the acquiree’s identifiable net assets. Acquisition costs incurred are expensed and included in administrative expenses.
When the Group acquires a business, it assesses the financial assets and liabilities assumed for appropriate classification and designation in
accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the
separation of embedded derivatives in host contracts by the acquiree.
If the business combination is achieved in stages, the acquisition date fair value of the acquirer’s previously held equity interest in the
acquiree is remeasured to fair value at the acquisition date through profit or loss.
Any contingent consideration to be transferred by the acquirer will be recognised at fair value at the acquisition date. Subsequent changes
to the fair value of the contingent consideration that is deemed to be an asset or liability will be recognised in accordance with AASB 139 in
profit or loss. If the contingent consideration is classified as equity it will not be remeasured. Subsequent settlement is accounted for within
equity. In instances where the contingent consideration does not fall within the scope of AASB 139, it is measured in accordance with the
appropriate AASB.
Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised for
non-controlling interest over the net identifiable assets acquired and liabilities assumed. If this consideration is lower than the fair value of
the net assets of the subsidiary acquired, the difference is recognised in profit or loss.
After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing,
goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group’s cash-generating units that are
expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquirer are assigned to those units.
Where goodwill forms part of the cash generating unit and part of the operation within that unit is disposed of, the goodwill associated with
the operation disposed of is included in the carrying amount of the operation when determining the gain or loss on disposal of the operation.
Goodwill disposed of in this circumstance is measured based on the relative values of the operation disposed of and the portion of the
cash-generating unit retained.
(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 2017. The adoption of
these new and revised Standards and Interpretations has not resulted in any changes to the Group’s accounting policies.
No changes in accounting policies or adjustments to the amounts recognised in the financial statements resulted from the adoptions of
these standards.
(ii) New Standards and Interpretations not yet adopted
Certain new accounting standards and interpretations have been published that are not mandatory for the current reporting period.
(a) AASB 15 Revenue from contracts with customers
The AASB has issued a new standard for the recognition of revenue. This will replace AASB 111 Construction Contracts, AASB 118 Revenue
and related IFRIC Interpretations. The new standard is based on the principle that revenue is recognised when control of a good or service
transfers to a customer.
The new standard is mandatory for the Group from 1 July 2018 and permits either a full retrospective or a modified retrospective approach
for the adoption. The Group intends to apply the full retrospective approach.
49
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(aa) Standards, Amendments and Interpretations (continued)
(ii) New Standards and Interpretations not yet adopted (continued)
(a) AASB 15 Revenue from contracts with customers (continued)
Management has undertaken an assessment of the effects of applying the new standard applying the following steps:
Identify contract with customers
Identifying the performance obligations in the contract
Determining the transaction price under the contract
Considering how the transaction price will be allocated to the performance obligations in the contract
Determining when revenue is recognized, upon satisfaction of performance obligations.
The Group has two types of revenue from customers being revenue from the sale of Natural Gas and revenue from the sale of Crude Oil.
Management has considered its natural gas sales and the impact of “take or pay” clauses included in long term gas sales agreements and has
concluded that the current policy for revenue recognition is consistent with the requirements of AASB 15. As a result revenue recognised in
respect of natural gas sales will not be impacted by the new standard based on current operations.
Crude oil is currently delivered to a sales point at Port Bonython and is invoiced in USD. The final oil price is calculated under a formula, the
calculation of which is contingent upon the date the crude is “lifted” from the Port. Management has concluded that the current policy for
revenue recognition satisfies the requirements of AASB 15.
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 is mandatory for the Group from 1 July 2018 and the
Group has not early adopted the new standard.
The Group has undertaken an assessment of the changes, and concluded that there will be no 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. The Group does not currently have any impairment provision for credit
losses. Receivables relate to credit worthy customers and Joint Venture partners and are collected in accordance with contractual
requirements.
(c) AASB 16 Leases
AASB 16 was issued in February 2016. It will result in almost all leases being recognised on the balance sheet, 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.
The standard will affect primarily the accounting for the Group’s operating leases. As at the reporting date, the Group has operating lease
commitments of $1,748,364. The Group expects the majority of these commitments will be recorded as a Lease Liability on the balance sheet
under AASB 16, however has not yet determined the exact extent that this will affect the Group’s profit and classification of cash flows. Some
of the commitments may be covered by the exception for short-term and low-value leases and some commitments may relate to
arrangements that will not qualify as leases under AASB 16.
The standard is mandatory for annual reporting periods beginning on or after 1 January 2019 which, for the Group, will be from 1 July 2019.
The group does not expect to adopt the standard early.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
50
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
2. OTHER INCOME
Interest
Research and development refunds (a)
Forgiveness of amounts due under Joint ventures (b)
Sale of exploration permits
Profit on disposal of inventory and other assets
Other income
Total other income
2018
$
525,109
—
—
280,000
224,415
25,660
1,055,184
2017
$
149,481
634,167
2,017,203
280,000
—
33,187
3,114,038
(a)
The research and development refunds received in 2017 were in respect of the financial year ended 30 June 2016 and were not
previously recognised as income as the amount and recoverability were uncertain at the time of preparation of the 2016 financial
statements.
(b) Under the terms of the Southern Georgina Farmout Agreement between wholly owned subsidiary Merlin Energy Pty Ltd (“Merlin”)
and Total GLNG Australia (“Total”), Total were required to pay for the first 80% of Stage 1 farmin expenditure and Merlin Energy were
required to pay for the last 20%. In February 2017, Total elected not to proceed to Stage 2 of the Farmin and to withdraw from the
Joint Venture. The Deed of Assignment, Assumption and Transfer of Total’s interests included releasing Merlin from all amounts
accrued up to the date of withdrawal by Total.
51
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
3. 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
Impairment expense
2018
$
350,202
3,657,662
3,950,098
33,414
2017
$
349,297
2,553,914
4,808,986
41,183
7,991,376
7,753,380
41,716
27,196
—
89,013
Rental expense relating to operating leases – Minimum lease payments
609.396
518,088
Revaluation of financial liabilities
3(b)
414,431
9,493,259
Finance costs
Interest charge on Macquarie debt facility
Interest paid to other suppliers
Interest on other financial liabilities
Borrowing costs on Macquarie and other debt facilities
Amortisation of deferred finance costs
Accretion charge
(b)
Individually significant items
Revaluation of financial liabilities
6,003,851
—
938,119
—
393,147
513,760
7,848,877
6,328,742
18,737
533,774
240
485,725
444,853
7,812,071
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.
As a result of the Group signing a new gas sales agreement during the 2017 year, under the applicable accounting standards, it was necessary
to re-assess the value of the financial settlement option under the Gas Sale and Prepayment Agreement. This resulted in an increase in the
recorded financial liability of $9,493,259 in the 2017 financial year.
In the 2018 financial year adjustments were made to the value of the financial liability to reflect the latest pricing and quantity assumptions
of the underlying agreements, as well as the expected completion date for the Northern Gas Pipeline, all of which impact either the timing
or amount of any potential financial settlement. These adjustments related in a total increase in the recorded financial liability amounting
to $414,431.
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.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
52
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
4.
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% (2017: 30%)
Tax effect of amounts which are not deductible in calculating taxable
income:
Non-deductible expenses
Share based payments
Non-assessable income (R&D Refund)
Other items
Sub-total
Under provision in prior year
Deferred tax assets not recognised
Recognition of previously unrecognised DTA
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
2018
$
2017
$
—
—
—
—
—
—
(14,076,129)
4,222,839
(24,726,481)
7,417,944
(309,262)
(486,699)
—
1,181
(147,002)
(675,307)
190,250
—
3,428,059
6,785,885
—
(3,428,059)
—
(6,785,885)
—
—
—
532,514
(532,514)
—
—
—
—
Unutilised tax losses for which no deferred tax asset has been recognised
131,114,647
120,670,253
Potential tax benefit at 30%
39,334,394
36,201,076
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.
53
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
4.
INCOME TAX (CONTINUED)
(e) Deferred tax assets and liabilities
Deferred tax assets
Provisions and accruals
Financial liabilities
Deferred revenue
Future deductible expenditure
Blackhole expenditure
Borrowing costs
PRRT
Unutilised losses
Total deferred tax assets before set-offs
Set-off of deferred tax liabilities pursuant to set-off provisions
2018
$
2017
$
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)
8,073,231
3,020,191
—
517,500
633,119
130,099
222,245,877
46,462,857
281,082,874
(12,050,541)
Net deferred tax assets not recognised
293,188,072
269,032,333
Movements
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
Acquired income
Capitalised exploration
Property, plant and equipment
PRRT
Total deferred tax assets before set-offs
Set-off of deferred tax liabilities pursuant to set-off provisions
Net deferred tax liabilities
Movements
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
12,050,541
1,865,471
10,720,341
1,330,200
13,916,012
12,050,541
12,060,386
1,855,626
10,849,394
1,201,147
13,916,012
12,050,541
12,061
463,254
9,930,815
3,509,882
4,007
450,254
9,296,490
2,299,790
13,916,012
(13,916,012)
12,050,541
(12,050,541)
—
—
12,050,541
1,865,471
10,720,341
1,330,200
13,916,012
12,050,541
13,903,950
12,062
12,046,535
4,006
13,916,012
12,050,541
(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. As at 30 June 2018 the Consolidated Entity has not recognised any potential tax benefits from the
objections lodged.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
54
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
5. 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 financial statements
(ii) Taxation services
Income Tax compliance
Other tax related services
(iii) Other services
Mereenie transaction due diligence
Technical accounting advice on major transactions
2018
$
2017
$
158,542
162,667
8,160
26,259
34,419
—
—
—
17,615
19,622
37,237
—
—
—
Total remuneration of PwC
192,961
199,904
6. CASH AND CASH EQUIVALENTS
Cash at bank and in hand
Made up as follows:
Corporate (a)
Joint arrangements (b)
27,222,845
5,478,140
26,706,273
516,572
27,222,845
5,081,168
396,972
5,478,140
(a) $1,782,026 of this balance relates to cash held with Macquarie Bank Limited to be used for allowable purposes under the Facility
Agreement (2017: $1,421,848), 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 32. The maximum exposure to credit risk at the end of the reporting period is
the carrying amount of cash and cash equivalents.
7. TRADE AND OTHER RECEIVABLES
Current
Trade receivables
Accrued income (a)
Other receivables
Prepayments
2018
$
1,556,150
4,121,642
57,541
896,309
2017
$
485,337
3,711,267
25,417
774,195
6,631,642
4,996,216
(a) Accrued income relates to the revenue recognition of oil and gas volumes delivered to respective customers but not yet invoiced.
The Group’s exposure to credit and currency risks and impairment losses related to trade and other receivables is disclosed in Note 32.
55
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
8.
INVENTORIES
Crude oil and natural gas
Spare parts and consumables
Drilling materials and supplies at cost
337,534
1,877,937
1,360,009
219,375
2,292,533
761,106
3,575,480
3,273,014
9. PROPERTY, PLANT AND EQUIPMENT
Year ended 30 June 2017
Opening net book amount
Additions
Changes to rehabilitation estimates
Disposals and write offs
Impairment
Depreciation charge
FREEHOLD LAND
AND BUILDINGS
$
PRODUCING
ASSETS
$
PLANT AND
EQUIPMENT
$
TOTAL
$
3,529,174
78,888,497
31,365,583
113,783,254
49,340
—
—
—
(349,297)
—
(225,435)
—
—
(2,553,914)
913,228
205,566
(67,201)
(89,013)
(4,850,169)
962,568
(19,869)
(67,201)
(89,013)
(7,753,380)
Closing net book amount
3,229,217
76,109,148
27,477,994
106,816,359
At 30 June 2017
Cost
Accumulated depreciation
3,868,743
(639,526)
84,443,566
(8,334,418)
44,844,266
(17,366,272)
133,156,575
(26,340,216)
Net book amount
3,229,217
76,109,148
27,477,994
106,816,359
Year ended 30 June 2018
Opening net book amount
Additions
Changes to rehabilitation estimates
Disposals and write offs
Depreciation charge
3,229,217
76,109,148
27,477,994
106,816,359
—
—
—
—
379,448
—
4,668,165
611
(19,838)
4,668,165
380,059
(19,838)
(350,202)
(3,657,662)
(3,983,512)
(7,991,376)
Closing net book amount
2,879,015
72,830,934
28,143,420
103,853,369
At 30 June 2018
Cost
3,868,743
84,823,014
49,442,072
138,133,829
Accumulated depreciation
(989,728)
(11,992,080)
(21,298,652)
(34,280,460)
Net book amount
2,879,015
72,830,934
28,143,420
103,853,369
10. EXPLORATION ASSETS
Acquisition costs of right to explore
Movement for the year:
Balance at the beginning of the year
Impairment of exploration assets
Balance at the end of the year
2018
$
2017
$
8,898,767
8,898,767
8,898,767
—
8,898,767
8,898,767
—
8,898,767
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
56
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
11.
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
12. OTHER FINANCIAL ASSETS
Current
Security deposits paid for drilling operations
2018
$
2017
$
379,615
(297,458)
82,157
82,157
115,576
—
(41,716)
156,017
495,191
(339,174)
156,017
358,365
(275,972)
82,393
82,393
27,014
(54)
(27,196)
82,157
379,615
(297,458)
82,157
2,333,333
—
Non-Current
Security bonds on exploration permits and rental properties
2,535,915
2,501,947
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.
13. 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 on an annual basis. The recoverable
amount of a Cash Generating Unit (“CGU”) is determined based on value-in-use calculations which require the use of assumptions. The
calculations use cash flow projections based on budgets for the next financial year as approved by management and forecasts beyond the
budget based on extrapolations using estimated growth rates.
Cash flows for revenues are based on contracted gas prices with allowance for CPI increases to prices where applicable.
57
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
13. GOODWILL (CONTINUED)
The following table sets out the key assumptions for the gas producing assets value-in-use calculations:
2018
Producing Assets
Sales volumes
Sales price (% annual growth rate)
Operating costs (% annual growth rate)
Pre-tax discount rate (%)
Contracted
2.5%
2.5%
14.0%
Management has determined the values assigned to each of the above key assumptions as follows:
Assumption
Approach used to determining values
Sales volume
Sales price
Operating costs
Natural Gas sales are based on Annual Contract Quantities for existing contracts which continue at projected
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.
Current contracted prices escalated for CPI increases as per contracts. Some contracts contain minimum and
maximum increases. Crude and condensate pricing is based on a mid-point of independent analyst forecasts
of crude prices and a long-term forecast average USD exchange rate.
Current budgeted operating costs 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.
Pre-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. The equivalent pre-tax discount rates are disclosed in the table above.
14. TRADE AND OTHER PAYABLES
Current
Trade payables
Other payables
Tax related payables
Deposits held
Accruals
2018
$
2,287,469
1,311
634,167
150,000
5,040,720
8,113,667
2017
$
2,552,400
492
—
—
686,276
3,239,168
Trade payables are usually non-interest bearing provided payment is made within the terms of credit. The Consolidated Entity’s exposure to
liquidity and currency risks related to trade and other payables is disclosed in Note 32.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
58
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
15. DEFERRED REVENUE
Proceeds received under Take-or-Pay gas sales contracts where gas is able to be taken by the customer in future periods:
Current
Proceeds received under Take-or-Pay gas sales contracts - Available to be
taken within 12-months (a)
Deferred revenue under other gas sales contracts (b)
Non-Current
Proceeds received under Take-or-Pay gas sales contracts - Available to be
taken after 12-months (a)
Deferred revenue under other gas sales contracts (b)
2018
$
2017
$
2,714,334
4,568,734
7,283,068
10,381,732
3,297,248
13,678,980
2,714,334
—
2,714,334
5,283,741
—
5,283,741
(a)
(b)
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 Limited 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 through a new Gas Sale Agreement. There was no cash settlement
option under the novation. This resulted in an amount of $7,865,982 being transferred from Other Financial Liabilities to Deferred
Revenue. Revenue will be recognised as gas is delivered to IPL.
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 32(e).
2018
$
2017
$
3,727,338
3,727,338
3,859,747
3,859,747
74,599,221
74,599,221
78,310,007
78,310,007
59
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
17. PROVISIONS
Employee entitlements (a)
Restoration and rehabilitation (b)
Joint Venture production over-lift (c)
2018
2017
Current Non-current
$
$
Total
$
2,883,557
522,958
—
660,179
21,639,197
3,541,059
3,543,736
22,162,155
3,541,059
Current Non-current
$
516,369
21,160,338
1,712,422
$
3,059,075
102,379
—
Total
$
3,575,444
21,262,717
1,712,422
3,406,515
25,840,435
29,246,950
3,161,454
23,389,129
26,550,583
(c)
(d)
(e)
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. The following amounts reflect leave that is not expected to be taken or paid within the next
12-months:
2018
$
2017
$
Current leave obligations expected to be settled after 12-months
778,897
706,408
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.
Movements in Provisions
Movements in each class of provision during the financial year are set out below:
Employee
Entitlements
$
Restoration &
Rehabilitation
$
Other
$
Total
$
3,575,444
21,262,717
1,712,422
26,550,583
2018
Carrying amount at start of year
Change in provision charged to property, plant and
equipment
Additional provisions charged to profit or loss
1,199,878
Reversal of previous provisions
Unwinding of discount
Amounts used during the year
—
—
(1,231,586)
5,619
—
513,760
—
—
380,059
—
1,828,637
—
—
—
380,059
3,034,134
—
513,760
(1,231,586)
Carrying amount at end of year
3,543,736
22,162,155
3,541,059
29,246,950
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
60
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
18. OTHER FINANCIAL LIABILITIES
Current
Lease incentive liabilities
Non-Current
Lease incentive liabilities
Liabilities associated with forward gas sales agreements containing a cash
settlement option (a)
2018
$
38,600
38,600
2017
$
38,600
38,600
83,633
122,233
15,278,873
15,362,506
21,792,304
21,914,537
(a)
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 2018 represents the remaining liabilities under the Second and Third
Contract Year.
19. CONTRIBUTED EQUITY
(a) Share capital
2018
$
2017
$
707,081,966 fully paid ordinary shares (2017: 433,197,647)
197,776,488
172,301,532
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.
(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
2017
No. of shares No. of shares
2018
2018
$
2017
$
433,197,647
433,197,647
172,301,532
172,301,532
92,000,980
180,499,020
—
1,384,319
—
—
—
—
9,200,098
18,049,902
(1,775,044)
—
—
—
—
—
Balance at end of year
707,081,966
433,197,647
197,776,488
172,301,532
(c) Movements in Share Options
There were no options granted or exercised during the year.
The following options over unissued ordinary shares lapsed during the year:
CLASS
Unlisted employee options
Unlisted employee options
Unlisted employee options
EXPIRY DATE
15 Nov 2017
15 Nov 2017
15 Nov 2017
EXERCISE
PRICE
$0.450
$0.400
$0.650
NUMBER OF
OPTIONS
26,168,035
365,100
27,300
(d) Unissued shares under option
At year end, options over unissued ordinary shares of the Company are as follows:
CLASS
Unlisted financing options
EXPIRY DATE
EXERCISE
PRICE
NUMBER OF
OPTIONS
01 Sep 2019
$0.200
30,000,000
None of the options entitle holders to participate in any share issue of the Company or any other entity.
61
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
19. CONTRIBUTED EQUITY (CONTINUED)
(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.
CLASS
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee LTIP rights
Employee 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
23 Sep 2020
05 Jan 2021
09 Feb 2021
08 Dec 2022
03 Oct 2022
08 Dec 2022
09 Feb 2022
03 Oct 2022
03 Oct 2022
18 Dec 2022
23 May 2023
28 Jun 2023
1 Jul 2014
1 Jul 2015
1 Jul 2015
1 Jul 2015
1 Jul 2015
1 Jul 2016
1 Jul 2016
1 Jul 2016
1 Jul 2017
1 Jul 2017
1 Jul 2017
1 Jul 2017
80,470
5,782,633
1,913,873
125,183
327,000
13,469,753
31,655
70,000
6,387,404
1,835,910
16,868
135,920
30,176,669
1,418,146 rights were converted to shares during the year (2017: Nil) and 1,523,870 rights were cancelled during the year. 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.
20. RESERVES
Share options reserve
Movements:
Balance at start of year
Share based payment costs (a)
Balance at end of year
2018
$
2017
$
23,463,784
21,841,455
21,841,455
1,622,329
23,463,784
19,590,431
2,251,024
21,841,455
(a)
The reserve is primarily used to record the value of share based payments provided to employees and Directors as part of their
remuneration and underwriters of share placements. Refer to Note 31 for further details of share based payments.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
62
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
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
2018
$
2017
$
(200,100,834)
(14,076,129)
(175,374,353)
(24,726,481)
(214,176,963)
(200,100,834)
(2.13)
(2.13)
(5.71)
(5.71)
(14,076,130)
(24,726,481)
660,637,923
516,313,022
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 EMT (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 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.
63
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
23. SEGMENT REPORTING (CONTINUED)
PRODUCING
ASSETS
2018
$
EXPLORATION
ASSETS
2018
$
CORPORATE
ITEMS CONSOLIDATION
2018
$
2018
$
34,939,194
(18,704,042)
16,235,152
—
—
—
—
—
16,235,152
(7,745,236)
(6,027,109)
(7,326,850)
(414,431)
(5,278,474)
—
—
—
504,415
—
—
—
—
—
—
—
550,769
(1,622,329)
(595,925)
(4,061,759)
—
34,939,194
(18,704,042)
16,235,152
1,055,184
(1,622,329)
(595,925)
(4,061,759)
—
504,415
(5,729,244)
11,010,323
—
(2,762,943)
(28,223)
—
(2,286,751)
(287,856)
—
(493,804)
—
(8,033,092)
(8,790,052)
(7,848,877)
(414,431)
(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
(136,584,039)
(2,828,327)
(12,637,964)
(152,050,330)
Revenue
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
Restatement of financial liability (b)
Loss before income tax
Taxes
Loss for the year
Segment assets
Segment liabilities
Capital expenditure
Property, plant and equipment
Total capital expenditure
4,433,420
4,433,420
—
—
234,745
234,745
4,668,165
4,668,165
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
64
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
23. SEGMENT REPORTING (CONTINUED)
Revenue
Cost of sales
Gross profit
Other income (a)
Share based employee benefits
General and administrative expenses
Employee benefits and associated costs
Other operating expenses
EBITDAX
Depreciation and amortisation
Exploration expenditure
Finance costs
Restatement of financial liability (b)
Impairment expense
PRODUCING
ASSETS
2017
$
EXPLORATION
ASSETS
2017
$
CORPORATE
ITEMS CONSOLIDATION
2017
$
2017
$
24,794,145
(15,701,690)
9,092,455
120,017
—
—
—
—
—
—
—
2,315,475
—
—
—
—
—
—
—
678,546
(2,251,024)
(1,946,659)
(5,658,990)
—
9,212,472
2,315,475
(9,178,127)
(7,488,544)
(471,532)
(7,265,784)
(9,493,259)
—
(8,087)
(1,429,850)
(15,749)
—
(89,013)
(283,945)
—
(530,538)
—
—
24,794,145
(15,701,690)
9,092,455
3,114,038
(2,251,024)
(1,946,659)
(5,658,990)
—
2,349,820
(7,78`0,576)
(1,901,382)
(7,812,071)
(9,493,259)
(89,013)
Loss before income tax
(15,506,647)
772,776
(9,992,610)
(24,726,481)
Taxes
Loss for the year
Segment assets
—
—
—
—
(15,506,647)
772,776
(9,992,610)
(24,726,481)
119,923,785
11,408,488
4,620,597
135,952,870
Segment liabilities
(127,314,178)
(1,659,886)
(12,936,653)
(141,910,717)
Capital expenditure
Property, plant and equipment
Total capital expenditure
599,361
599,361
—
—
363,207
363,207
962,568
962,568
(a)
(b)
Under the terms of the Southern Georgina Farmout Agreement between Merlin Energy Pty Ltd (“Merlin”) and Total GLNG Australia
(”Total”), Total were required to pay for the first 80% of Stage 1 farmin expenditure and Merlin Energy were required to pay for the
last 20%. In February 2017 Total elected not to proceed to Stage 2 of the Farmin and to withdraw from the Joint Venture. The Deed
of Assignment, Assumption and Transfer of Total’s interests included releasing Merlin from all amounts accrued up to the date
of withdrawal by Total. The extinguishment of the liability of $2,017,000 is recorded as other income for 2017 under the
Exploration segment.
In 2016 the Group entered into a Gas Sale and Prepayment Agreement with Macquarie Group, 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 the 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. As a result of the Group signing a new gas sales agreement
during the 2017 year, under the applicable accounting standards, it was necessary to re-assess the value of the financial settlement
option under the Gas Sale and Prepayment Agreement. This resulted in an increase in the recorded financial liability of $9,493,259
and an expense for the same amount recorded in the 2017 year. The financial liability is reviewed regularly for updates to pricing and
timing assumptions. This resulted in an expense of $414,431 in the 2018 financial year. A financial settlement would be paid out of
the proceeds of gas sold under the new gas sales agreements. See also Notes 3 and 18.
65
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
23. SEGMENT REPORTING (CONTINUED)
Revenue from external customers by geographical location of production
Australia
Non-current assets by geographical location
Australia
2018
$
2017
$
34,939,194
24,794,145
119,350,338
122,205,500
Major Customers
Customers with revenue exceeding 10% of the group’s total oil and gas sales revenue are shown below.
Largest customer
Second largest customer
Third largest customer
Fourth largest customer
Fifth largest customer
2018
$
% of Sales
Revenue
2017
$
% of Sales
Revenue
8,665,876
6,948,934
6,314,195
5,250,226
4,008,261
25%
20%
18%
15%
11%
7,600,694
6,398,720
5,632,967
—
—
31%
26%
23%
—
—
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
Total liabilities
Net assets
Shareholders’ equity
Issued capital
Reserves
Accumulated losses
Total equity
Loss for the year
Total comprehensive loss
2018
$
28,495,981
9,075,508
37,571,489
(24,299,693)
(25,257,763)
12,313,726
2017
$
5,999,204
9,131,712
15,130,916
(7,656,045)
(8,503,576)
6,627,340
197,776,487
23,463,783
(208,926,544)
12,313,726
(21,410,897)
172,301,532
21,841,455
(187,515,647)
6,627,340
(8,769,073)
(21,410,897)
(8,769,073)
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
66
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
24. PARENT ENTITY INFORMATION (CONTINUED)
(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 Macquarie Loan Facility exists under which the parent and non-borrowing subsidiaries have provided guarantees to Macquarie Bank 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 Surprise)
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 30(c).
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
Merlin Energy Pty Ltd
Central Petroleum Projects Pty Ltd
(formerly Merlin West Pty Ltd)
Helium Australia Pty Ltd
Ordiv Petroleum Pty Ltd
Frontier Oil & Gas Pty Ltd
Central Petroleum Eastern Pty Ltd
(formerly Central Green 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
PLACE OF
INCORPORATION
CLASS OF
SHARES
Western Australia
Ordinary
Western Australia
Victoria
Western Australia
Western Australia
Western Australia
Western Australia
Western Australia
Queensland
Queensland
Queensland
Queensland
N/A
Queensland
Queensland
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Units
Ordinary
Ordinary
(c) Key management personnel
Disclosures relating to key management personnel are set out in Note 26.
EQUITY HOLDING
2018
2017
%
%
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
Nil
Nil
67
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
26. KEY MANAGEMENT PERSONNEL
(a) Key management personnel compensation
Short-term employee benefits
Post-employment benefits
Termination benefits
Long-term benefits
Share based payments
2018
$
2,561,475
139,774
—
59,756
1,097,869
2017
$
2,373,766
142,141
—
46,583
1,798,104
3,858,874
4,360,594
Detailed remuneration disclosures are provided in the remuneration report on pages 23 to 32.
(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) Option holdings
There were no options on issue to key management personnel at 30 June 2018. The number of options over ordinary 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:
BALANCE
AT START
OF YEAR
GRANTED AS
COMPENSATION
EXERCISED
EXPIRED OR
FORFEITED
HELD AT
DATE OF
DEPARTURE
BALANCE AT
END OF YEAR
VESTED
EXERCISABLE
UNVESTED
Non-Executive Directors
Wrixon Gasteen
2018
2017
—
666,666
—
—
Executive Directors and Other Key Management Personnel
Richard Cottee1
Leon Devaney
Michael Herrington
Daniel White
2018
2017
2018
2017
2018
2017
2018
2017
24,900,773
24,900,773
—
504,000
—
1,950,000
—
760,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(666,666)
(24,900,773)
—
—
(504,000)
—
(1,950,000)
—
(760,000)
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
—
—
—
24,900,773
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
24,900,773
—
—
—
—
—
—
1 On 8 August 2012, 34,584,407 unlisted options exercisable at $0.45 on or before 15 November 2015 and 15 November 2017 were issued to FEP, a company in which
Richard Cottee has a 50% beneficial interest. Remaining options expired on 15 November 2017.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
68
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
26. KEY MANAGEMENT PERSONNEL (CONTINUED)
(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:
RIGHTS HELD
AT START
OF YEAR
MAXIMUM NO.
GRANTED AS
COMPENSATION
CANCELLED
DURING THE
YEAR
HELD AT
DATE OF
DEPARTURE
CONVERTED
TO SHARES
RIGHTS HELD
AT END
OF YEAR)
Executive Directors and Other Key Management Personnel
Richard Cottee
Leon Devaney
Ross Evans2
Michael Herrington
Robin Polson1
Daniel White
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
5,307,887
2,104,904
2,373,104
1,061,571
N/A
N/A
2,886,237
930,000
N/A
N/A
2,389,666
1,100,000
1,854,229
3,202,983
917,339
1,311,533
—
N/A
931,057
1,956,237
—
N/A
767,966
1,289,666
(104,675)
—
(152,643)
—
—
N/A
(218,397)
—
—
N/A
(180,824)
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
(104,675)
—
(152,642)
—
—
N/A
(218,396)
—
—
N/A
(180,823)
—
6,952,766
5,307,887
2,985,158
2,373,104
—
N/A
3,380,501
2,886,237
—
N/A
2,795,985
2,389,666
1 Robin Polson commenced 1 May 2018
2 Ross Evans commenced 1 June 2018
69
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
26. 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
Non-Executive Directors
Wrixon Gasteen
Robert Hubbard1
Martin Kriewaldt2
Peter Moore
Sarah Ryan2
Timothy Woodall3
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
136,473
136,473
298,947
298,947
N/A
N/A
—
—
N/A
N/A
N/A
N/A
—
—
—
—
200,000
N/A
—
—
—
N/A
1,000,000
N/A
156,864
—
365,667
—
900,000
N/A
265,000
—
105,000
N/A
500,000
N/A
Executive Directors and Other Key Management Personnel
—
—
—
—
—
N/A
—
—
—
N/A
—
N/A
Richard Cottee
Leon Devaney
Ross Evans6
Michael Herrington
Robin Polson5
Daniel White
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
571,829
632,438
210,000
210,000
N/A
N/A
250,000
250,000
N/A
N/A
288,000
288,000
—
—
—
—
—
N/A
—
—
—
N/A
—
—
216,929
104,675
—
266,380
—
—
N/A
104,168
—
—
N/A
160,000
—
—
152,642
—
—
N/A
218,396
—
—
N/A
180,823
—
—
—
—
—
—
N/A
—
—
—
N/A
—
N/A
(3,500)4
(60,609)4
—
—
—
N/A
—
—
—
N/A
—
—
N/A
N/A
664,614
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
293,337
136,473
N/A
298,947
1,100,000
N/A
265,000
—
105,000
N/A
1,500,000
N/A
889,933
571,829
629,022
210,000
—
N/A
572,564
250,000
—
N/A
628,823
288,000
Robert Hubbard retired 14 May 2018
1
2 Martin Kriewaldt and Sarah Ryan were appointed Directors 23 October 2017
3
4
5
6
Timothy Woodall was appointed Director 20 December 2017
Shares held by members of Mr Cottee’s family and no longer considered under Mr Cottee’s control have been removed from this table.
Robin Polson commenced 1 May 2018
Ross Evans commenced 1 June 2018
(c) Other transactions with key management personnel
There were no other transactions with Key Management Personnel
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
70
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
27. RECONCILIATION OF LOSS AFTER INCOME TAX TO NET CASH
OUTFLOW FROM OPERATING ACTIVITIES
Loss after income tax
Adjustments for:
Depreciation and amortisation
(Profit)/Loss on disposal of assets
Profit on disposal of exploration permits
Share-based payments
Impairment expense
Restatement of financial liabilities
Financing costs and interest (non-cash)
Changes in assets and liabilities relating to operating activities:
(Increase) / Decrease in trade and other receivables
Decrease in inventories
Decrease in other financial assets
Increase/(Decrease) in trade and other payables
Increase in deferred revenue
Increase in financial liabilities
Increase in provisions
2018
$
2017
$
(14,076,129)
(24,726,481)
8,033,092
(13,799)
(280,000)
1,622,329
—
414,431
1,347,819
(1,634,805)
(302,466)
—
2,687,060
5,097,991
(38,600)
2,316,307
7,780,576
47,665
(280,000)
2,251,024
89,013
9,493,259
1,019,499
(1,208,938)
319,547
17,785
(1,893,483)
4,030,668
160,833
2,665,032
Net cash inflow/(outflow) from operations
5,173,230
(234,001)
28. CASH FLOW INFORMATION
Non-cash investing and financing activities
(a)
Non-cash interest relating to Other Financial Liabilities amounted to $938,119 (2017: $533,774). Additionally, non-cash revaluation expense
amounted to $414,431 (2017: $9,493,259). Refer Note 3(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 $7,865,982 was transferred to Deferred Revenue, reflecting the removal of the cash settlement option for the
First contract year. (Refer Note 15 and 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.
71
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
28. CASH FLOW INFORMATION (CONTINUED)
(b) Net debt reconciliation (continued)
Net debt
2018
$
27,222,845
(3,727,338)
(74,599,221)
(51,103,714)
2017
$
5,478,140
(3,606,853)
(78,310,007)
(76,438,720)
27,222,845
(78,326,559)
5,478,140
(81,916,860)
(51,103,714)
(76,438,720)
Other Assets
Liabilities from
financing activities
Cash
$
Borrowings due
within 1 year
$
Borrowings due
after 1 year
$
Total
$
15,115,699
(3,514,275)
(81,916,860)
(70,315,436)
(9,637,559)
—
—
4,000,000
(3,606,853)
(485,725)
—
(5,637,559)
3,606,853
—
—
(485,725)
5,478,140
(3,606,853)
(78,310,007)
(76,438,720)
21,744,705
—
—
4,000,000
(3,710,786)
(409,699)
—
25,744,705
3,710,786
—
—
(409,699)
27,222,845
(3,727,338)
(74,599,221)
(51,103,714)
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 2016
Cash flows
Reclassification of category
Other non-cash movements
Net debt 30 June 2017
Cash flows
Reclassification of category
Other non-cash movements
Net debt 30 June 2018
29. CONTINGENCIES
(a) Contingent liabilities
(i)
Exploration Permits
The Consolidated Entity had contingent liabilities at 30 June 2018 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 (2017: $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 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.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
72
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
29. 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.
(iii) Litigation
The Company has been sued in litigation filed in the District Court of Harris County, located in Houston, Texas, by Geoscience Resource
Recovery, LLC (“GRR”) in respect of a farm-in deal negotiated between the Perth office of Total S.A. and the Company when it was
headquartered in Perth. In the lawsuit, GRR alleges that in February 2012, the Company agreed to pay GRR a certain commission if
the Company entered into a farm-in agreement with a farminee brought to it by GRR. GRR alleges that it introduced the Company to
Total S.A. and because the Company subsequently entered into a farm-in agreement with Total S.A., the Company is obligated to pay
GRR the commission. The Company has denied any liability and has also challenged the jurisdiction of the Texas court. The trial court
denied the Company’s objection to the court’s jurisdiction and Company’s appeal to the Court of Appeals from that order was not
successful. The Company, however, has filed a Petition for Review with the Supreme Court of Texas, and the Court recently requested
further briefing on the issue.
The Company also filed proceedings in the Supreme Court of Queensland against GRR seeking, among other things, declarations, that
the Company did not enter into and is not bound by an alleged agreement to pay GRR certain fees, and that the Company is not liable
to GRR for a fee or any other sum in relation to the farm-in deal. GRR opposed jurisdiction of the Supreme Court of Queensland.
GRR’s application was dismissed in the Company’s favour in October 2017. GRR appealed the decision which appeal was dismissed
in the Company’s favour on 14 September 2018.
(iv)
In July 2018 the group entered into an Amending Deed with Macquarie Mereenie Pty Limited to amend the Mereenie Joint Operating
Agreement effective from 22 June 2018, whereby Central Petroleum will fund any over expenditures arising from the Mereenie Plant
expansion project in excess of the project authorised amount plus $1 million.
Current project forecasts indicate the project costs will be within the authorised amount and therefore Central ascribes no value to
this contingent liability at the date of this report.
30. 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
2018
$
2017
$
1,675,020
—
—
1,675,020
—
—
—
—
14,155,000
13,325,000
11,050,000
4,630,000
25,180,000
2,400,000
38,530,000
32,210,000
73
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
30. COMMITMENTS (CONTINUED)
(b) Exploration commitments (continued)
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 through its parent entity, Central Petroleum Limited, has non-cancellable operating leases for office premises and
accommodation in Alice Springs and Brisbane. 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
31. SHARE BASED PAYMENTS
560,413
1,221,665
1,782,078
465,421
1,404,222
1,869,643
(a) Employee options
An Incentive Option Scheme operates 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.
At the discretion of the Company, performance criteria may or may not be established in respect of options that vest under the Incentive
Option Scheme. Options are granted for no consideration. Options that have been granted to date to employees, excluding Directors, have
contained service conditions in respect of their vesting. Options have vested progressively from grant date to, in some cases, an employee’s
third anniversary. As of the date of this report no options issued under the Incentive Option Scheme have contained any performance criteria
in respect of their vesting.
There are no rules imposing a restriction on removing the ‘at risk’ aspect of options granted to employees or Directors. One ordinary share
is issued upon exercise of one option.
Set out below are summaries of options that have been granted to Directors and employees.
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
Weighted average remaining contractual life (years) at the end of the year
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
74
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
31. SHARE BASED PAYMENTS (CONTINUED)
(a) Employee options (continued)
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.
$
2017
20 Jul 2016
19 Aug 2016
30 Aug 2016
15 Nov2016
30 Nov 2016
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
$0.550
$0.575
$0.575
$0.475
$0.475
$0.450
$0.450
$0.475
$0.450
$0.400
$0.410
$0.650
669,334
400,000
600,000
2,318,668
400,000
24,900,773
2,733,335
2,799,350
2,429,068
782,525
234,000
393,900
—
—
—
—
—
—
—
—
430,827
—
—
—
Totals
38,660,953
430,827
Weighted average exercise price
$0.46
$0.45
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(669,334)
(400,000)
(600,000)
(2,318,668)
(400,000)
—
—
—
—
—
—
24,900,773
(1,266,668)
1,466,667
(2,799,350)
—
(1,059,300)
1,800,595
(417,425)
(234,000)
(366,600)
365,100
—
27,300
(10,531,345)
28,560,435
$0.49
$0.45
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Weighted average remaining contractual life (years) at the end of the year
0.38
(b) Employee options granted during the year
No options were granted during the year ended 30 June 2018.
The following options were granted during the year ended 30 June 2017:
GRANT DATE EXPIRY DATE
2017
NUMBER OF
OPTIONS
AVERAGE
FAIR VALUE
PER OPTION
EXERCISE
PRICE
PRICE OF
SHARES ON
GRANT DATE
ESTIMATED
VOLATILITY*
RISK FREE
INTEREST
RATE
DIVIDEND
YIELD
07 Mar 2017
15 Nov 2017
430,827*
$Nil
$0.450
$0.150
80-90%
1.84%
0.0%
*
Issued to former employees under the 2012 Employee Share Option Plan. Options contain a vesting share price hurdle of $1.45 per share
(c) 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 three years is 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.
75
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
31. SHARE BASED PAYMENTS (CONTINUED)
(c) Deferred shares — Long Term Incentive Plan (continued)
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:
GRANT DATE
PLAN YEAR
END
BALANCE AT
START OF
YEAR
NUMBER OF
RIGHTS
GRANTED
AVERAGE FAIR
VALUE PER
OPTION
EXERCISED
DURING THE
YEAR
CANCELLED
OR FORFEITED
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
Totals
2017
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
7,160,584
449,218
33,052
106,666
—
—
—
—
—
—
$0.190
$0.151
$0.106
$0.135
$0.135
$0.087
$0.123
$0.165
$0.184
$0.147
$0.085
$0.074
22 Dec 2015
30 June 2016
1,913,873
03 Dec 2015
30 June 2016
09 Nov 2015
30 June 2016
6,063
528,415
14 Oct 2015
30 June 2016
5,344,370
22 Dec 2015
30 June 2015
191,031
17 Jun 2015
30 June 2015
2,537,112
Totals
10,520,864
13,831,490
—
—
—
—
—
—
—
—
(9,159)
(9,160)
(109,776)
(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)
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
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(107,200)
(43,500)
(4,291)
—
—
—
(6,666)
(82,883)
—
(38,856)
31,655
6,050,315
7,053,384
405,718
28,761
106,666
1,913,873
6,063
521,749
5,261,487
191,031
2,498,256
(283,396)
24,068,958
24,068,958
9,049,727
(1,418,146)
(1,523,870)
30,176,669
(1,203,695)
(1,221,132)
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
76
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
31. SHARE BASED PAYMENTS (CONTINUED)
(d) Expenses arising from share-based payment transactions
Total expenses arising from share-based transactions recognised during the year were:
Options and rights issued to Directors and employees
32. FINANCIAL RISK MANAGEMENT
2018
$
2017
$
1,622,329
2,251,024
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 doubtful debts. 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
Past due: 0-30 days
Past due: 31-150 days
Past due: 151-365 days
GROSS
2018
$
2017
$
5,735,333
4,222,021
—
—
—
—
5,735,333
4,222,021
IMPAIRMENT
2018
$
—
—
—
—
2017
$
—
—
—
—
Based on historic default rates, the Consolidated Entity believes that no impairment allowance is necessary in respect of receivables past due
over 30 days.
The receivables at 30 June 2018 relate predominantly to the oil and gas sales from Mereenie and gas sales from the Dingo field. 100% of
trade and other receivables have been received to date.
Credit risk also arises in relation to financial guarantees given to certain parties (refer Note 24(b)). Such guarantees are only provided in
exceptional circumstances and are subject to specific Board approval.
77
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
32. FINANCIAL RISK MANAGEMENT (CONTINUED)
(b) Liquidity Risk
The following are the contractual maturities of financial assets and liabilities:
2018
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
2017
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
≤ 6 MONTHS 6–12 MONTHS
1–5 YEARS
≥ 5 YEARS
TOTAL
27,222,845
5,735,333
2,333,333
35,291,511
(8,113,667)
(1,858,626)
(19,300)
—
—
—
—
—
—
—
2,535,915
2,535,915
—
(1,868,712)
(74,599,221)
(19,300)
(15,362,506)
(9,991,593)
(1,888,012)
(89,961,727)
—
—
—
—
—
—
—
—
27,222,845
5,735,333
4,869,248
37,827,426
(8,113,667)
(78,326,559)
(15,401,106)
(101,841,332)
≤ 6 MONTHS 6–12 MONTHS
1–5 YEARS
≥ 5 YEARS
TOTAL
5,478,140
4,222,021
—
9,700,161
(3,239,168)
(2,213,743)
(19,300)
—
—
—
—
—
—
—
2,501,947
2,501,947
—
(1,646,004)
(78,310,007)
—
—
—
—
—
—
5,478,140
4,222,021
2,501,947
12,202,108
(3,239,168)
(82,169,754)
(19,300)
(21,646,784)
(267,753)
(21,953,137)
(5,472,211)
(1,665,304)
(99,956,791)
(267,753)
(107,362,059)
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 6) on the basis of 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.
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
78
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
32. FINANCIAL RISK MANAGEMENT (CONTINUED)
Interest Rate Risk
(c)
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-BEARING INTEREST
TOTAL
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
%
%
$
$
1.1
27,222,845
5,478,140
—
1.1
—
—
—
—
$
—
—
$
—
—
$
—
$
$
$
—
27,222,845
5,478,140
5,735,333
4,222,021
5,735,333
4,222,021
3,495,930
1,233,410
1,373,318
1,268,537
4,869,248
2,501,947
27,222,845
5,478,140
3,495,930
1,233,410
7,108,651
5,490,558
37,827,426
12,202,108
—
—
—
7.4 (78,326,559)
(81,916,861)
—
—
—
(78,326,559)
(81,916,861)
—
—
—
—
— (8,113,667)
(3,239,168)
(8,113,667)
(3,239,168)
(252,893)
—
— (78,326,559)
(82,169,754)
— (15,401,106)
(21,953,137)
(15,401,106)
(21,953,137)
(252,893)
(23,514,773)
(25,192,305)
(101,841,332) (107,362,059)
(51,103,714)
(76,438,721)
3,495,930
980,517 (16,406,122)
(19,701,747)
(64,013,906)
(95,159,951)
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)
1.7
—
1.2
—
7.7
—
Interest Rate Sensitivity
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 2017.
PROFIT OR LOSS
EQUITY
10% Increase
10% Decrease
10% Increase
10% Decrease
2018
Cash and cash equivalents
Interest bearing liabilities
2017
Cash and cash equivalents
Interest bearing liabilities
46,419
(604,182)
6,210
(603,045)
(46,419)
604,182
(6,210)
603,045
—
—
—
—
—
—
—
—
These movements would not have any impact on equity other than retained earnings.
79
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
32. FINANCIAL RISK MANAGEMENT (CONTINUED)
(d) Commodity Risk
Gas sales are made under long term contracts and as such do not contain any commodity risk. The Consolidated Entity is exposed to
commodity price fluctuations in respect of crude oil sales. 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
2018
Other financial liabilities
2017
Other financial liabilities
—
1,040,756
(1,730,218)
952,587
—
—
—
—
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
2018
Other financial liabilities
2017
Other financial liabilities
(152,789)
152,789
(549,107)
106,703
—
—
—
—
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 million along with accrued interest. 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 Loan”). As at 30 June 2018 the
Group has not drawn on this facility. Should the Group draw down on the Second Facility D Loan, it will be repayable in quarterly instalments
over calendar year 2019.
In September 2018 Macquarie agreed to increase the facility by a further $7.5 million (refer Note 34 for further details).
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
80
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
32. FINANCIAL RISK MANAGEMENT (CONTINUED)
(e) Financing Facilities (continued)
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 all associated contracts
completed in Australian dollars. A foreign exchange risk arises 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
2018
$
2017
$
2,129,035
1,492,790
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%
2018
$
(193,549)
212,904
2017
$
(135,708)
149,279
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.
33. INTEREST 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 (Santos)
EP 105 (Santos)
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
EP 106 (Santos)
EP 112 (Santos)
EP 125 (Santos)
EP 115 North Mereenie Block (Santos2)
EPA 111 (Santos2)
EPA 124 (Santos2)
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration – application
Oil & gas exploration – application
1 Macquarie Mereenie acquired 50% interest form Santos effective 1 January 2017
2
Santos = Santos Group companies
2018
%
50.00
60.00
60.00
60.00
60.00
30.00
60.00
50.00
50.00
2017
%
50.00
60.00
60.00
60.00
60.00
30.00
60.00
50.00
50.00
81
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
33. INTEREST IN JOINT ARRANGEMENTS (CONTINUED)
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, otherwise may be subject to change or negotiation.
ATP 2031 (under application)
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. Central has been announced as the preferred bidder but as at 30 June 2018 the Permit had not been formally
granted. 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.
In August 2018, the Queensland government formally awarded the permit to Central.
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:
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)
2018
$
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
2017
$
396,972
3,139,181
1,357,192
—
4,893,345
52,143,932
175,000
52,318,932
605,789
381,094
730,878
1,717,761
439,497
1,712,422
11,658,569
13,810,488
41,684,028
Joint arrangement contribution to loss before tax
Revenue
Other income
Expenses
Profit / (Loss) before income tax
25,680,706
29,662
(21,646,937)
4,063,431
15,263,637
2,017,203
(18,678,419)
(1,397,579)
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
82
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2018
34. EVENTS OCCURRING AFTER THE REPORTING PERIOD
In July 2018, it was announced that Mr Richard Cottee will cease employment on 31 January 2019. Mr Leon Devaney is acting CEO in the
interim period.
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. As at 30 June 2018 the Consolidated Entity has not recognised any potential tax benefits from the
objections lodged.
In August 2018, Central was formally awarded ATP 2031 by the Queensland government.
GRR’s appeal opposing jurisdiction in the Supreme Court of Queensland was dismissed in the Company’s favour on 14 September 2018 (refer
to Note 29 (a) (iii) for further details).
On 26 September 2018 the Consolidated Entity’s debt facility with Macquarie Bank was extended by a further $7.5 million. Drawdowns under
this extension are at Central’s election and will be repayable in equal instalments from April to December 2019. As part of the arrangement
the Company will grant Macquarie Bank up to 22.5 million options with an exercise price of 14 cents and expiring December 2019. Options
will be granted in four equal tranches, the first on completion of the agreement and the remaining tranches as funds drawn down under the
facility reach certain thresholds.
On 27 September 2018 Central Petroleum Limited secured a $10,000,000 facility with Hong Kong based investment company Long State
Investment Limited (“LSI”). Under the terms of the facility, Central Petroleum Limited may, at its discretion, issue shares to LSI at any
time over the next 24 months, up to a total of $10,000,000. Central Petroleum Limited may draw down up to $250,000 in any period of
5 trading days.
Shares issued to LSI will be priced at the lowest daily volume weighted average price (“VWAP”) of Central Petroleum Limited shares traded
on each of the 5 trading days which follow an advance notice by Central Petroleum Limited. A commission of 5% will be payable by Central
Petroleum Limited at the time of issue.
LSI may receive up to 5 million unlisted options through four separate tranches that are 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 Central is required to grant the options, will be
granted when the aggregate advances first exceeds $2.5 million, $5.0 million, and $7.5 million. The options have an exercise period of
five years from the date of issue. To date, Central has not utilised the ELOC and no options have been granted.
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.
83
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
DIRECTORS’ DECLARATION
In the Directors’ opinion:
a)
the financial statements and notes set out on pages 36 to 83 of the Consolidated Entity are in accordance with the Corporations Act
2001 (Cth), including:
(i)
(ii)
complying with Accounting Standards, the Corporations Regulations 2001 (Cth) and other mandatory professional reporting
requirements, and
giving a true and fair view of the Consolidated Entity’s financial position as at 30 June 2018 and of its performance for the financial
year ended on that date;
b)
c)
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
the financial statements comply with the International Financial Reporting Standards as issued by the International Accounting
Standards Board as disclosed in Note 1(a).
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 2018.
This declaration is made in accordance with a resolution of the Directors of Central Petroleum Limited:
Martin Kriewaldt
Director
Brisbane
28 September 2018
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
84
INDEPENDENT AUDITOR’S REPORT
85
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
INDEPENDENT AUDITOR’S REPORT
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
86
87
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
INDEPENDENT AUDITOR’S REPORT
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
88
89
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
ASX ADDITIONAL INFORMATION
DETAILS OF QUOTED SECURITIES AS AT 30 AUGUST 2018
Top holders
The 20 largest registered holders of the quoted securities as at 30 August 2018 were:
NAME
UBS Nominees Pty Ltd
Mr. Christopher Ian Wallin + Ms Fiona Kay McLoughlin + Mrs Sylvia Fay Bhatia
HSBC Custody Nominees (Australia) Limited – A/C 2
Rocket Science Pty Ltd
National Nominees Limited
Macquarie Bank Limited
Citicorp Nominees Limited
Fanchel Pty Ltd
Telunapa Pty Ltd.
Kensington Capital Partners Pty Ltd
National Nominees Limited
Norfolk Enchants Pty Ltd
JH Nominees Australia Pty Ltd
Safari Capital Pty Ltd
Chembank Pty Limited
Mr. Jamie Pherous
J P Morgan Nominees Australia Limited
Bond Street Custodians Ltd
Edwin Holdings Pty Ltd
Justwright Investments Pty Ltd
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
NO. OF
SHARES
32,632328
17,571,648
16,602,906
15,800,000
14,877,697
14,166,667
13,994,187
12,716,667
10,541,667
8,345,173
7,485,949
7,400,000
6,700,000
5,484,967
5,000,000
5,000,000
4,947,391
4,767,155
4,604,167
4,500,000
%
4.61
2.48
2.35
2.23
2.10
2.00
1.98
1.80
1.49
1.18
1.06
1.05
0.95
0.78
0.71
0.71
0.70
0.67
0.65
0.64
213,138,569
30.14
DISTRIBUTION SCHEDULE
The distribution schedule of the ordinary fully paid shares as at 30 August 2018 was:
RANGE
1 - 1,000
1,001 - 5,000
5,001 - 10,000
10,001 - 100,000
100,001 - Over
HOLDERS
802
2,141
1,150
2,969
UNITS
369,324
5,889,802
9,000,559
114,367,251
989
577,488,857
%
0.05
0.83
1.27
16.18
81.67
Total
8,051
707,115,793
100.00
SUBSTANTIAL SHAREHOLDERS
Substantial shareholders as disclosed by notices received by the Company as at 30 August 2018 with holdings of 5% or more of the total
votes attached to the voting shares or interests in the Entity:
HOLDER
UNITS
Troy Harry
38,245,173
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 90
ASX ADDITIONAL INFORMATION
UNMARKETABLE PARCELS
Holdings less than a marketable parcel of ordinary shares (being 5,000 shares as at 30 August 2018):
HOLDERS
UNITS
2,411
3,889,395
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.
91
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT
INTERESTS IN PETROLEUM PERMITS AND PIPELINE
LICENCES AT THE DATE OF THIS REPORT
PERMITS AND LICENCES GRANTED
TENEMENT
LOCATION
OPERATOR
EP 82 (excl. EP 82 Sub-Blocks) 1
Amadeus Basin NT
Amadeus Basin NT
EP 82 Sub-Blocks
EP 93 4
Pedirka Basin NT
EP 97 4
Pedirka Basin NT
EP 105 1
Amadeus/Pedirka Basin NT
EP 106 3
Amadeus Basin NT
EP 107 4
Amadeus/Pedirka Basin NT
EP 112 1
Amadeus Basin NT
EP 115 (excl. EP 115NMB)
Amadeus Basin NT
EP 115NMB (North Mereenie Block) Amadeus Basin NT
Amadeus Basin NT
EP 125
Amadeus Basin NT
OL 3 (Palm Valley)
OL 4 (Mereenie)
Amadeus Basin NT
OL 5 (Mereenie)
L 6 (Surprise)
L 7 (Dingo)
RL 3 (Ooraminna)
RL 4 (Ooraminna)
ATP 909
ATP 911
ATP 912
ATP 2031 6
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Georgina Basin QLD
Georgina Basin QLD
Georgina Basin QLD
Walloon Fairway QLD
Santos
Central
Central
Central
Santos
Santos
Central
Santos
Central
Santos
Santos
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
CTP CONSOLIDATED
ENTITY
OTHER JV PARTICIPANTS
Registered
Interest (%)
Beneficial
Interest (%)
Participant
Name
Beneficial
Interest (%)
60
100
100
100
60
60
100
60
100
60
30
100
50
50
100
100
100
100
100
100
100
100
60
100
0
0
60
60
0
60
100
60
30
100
50
50
100
100
100
100
100
100
100
50
Santos
40
Santos
Santos
Santos
Santos
Santos
Macquarie
Mereenie
Macquarie
Mereenie
40
40
40
40
70
50
50
Incitec Pivot
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
EPA 160
EPA 296
Wiso Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Wiso Basin NT
Pedirka Basin NT
Pedirka Basin NT
Georgina Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Wiso Basin NT
Wiso Basin NT
Central
Santos
Central
Santos
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
50
100
50
100
100
100
100
100
100
100
100
100
100
100
Santos
Santos
50
50
2018 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
92
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
Amadeus Basin NT
Amadeus Basin NT
Central
Central
50
100
50
100
Macquarie
50
1
2
3
4
5
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 subject to approval from the NT government and Department of
Primary Industry and Resources.
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
ATP 2031 was granted in August 2018.
93
CENTRAL PETROLEUM LIMITED 2018 ANNUAL REPORT