CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
Annual report
30 June 2014
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
CONTENTS
Corporate Directory ..........................................................................................................................................2
Chairman’s Letter .............................................................................................................................................3
Managing Director’s Letter ...............................................................................................................................5
Directors’ Report ..............................................................................................................................................6
Auditor’s Declaration of Independence ..........................................................................................................33
Corporate Governance Statement .................................................................................................................34
Financial Statements .....................................................................................................................................40
Directors’ Declaration .....................................................................................................................................88
Independent Auditor’s Report ........................................................................................................................89
ASX Additional Information ............................................................................................................................91
Interests in Petroleum Permits and Pipeline Licences ...................................................................................93
1
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
CORPORATE DIRECTORY
DIRECTORS
Andrew P Whittle BSc (Hons), Non-executive Chairman
Richard I Cottee BA LLB (Hons), Managing Director and Chief Executive Officer
Michael R Herrington BSc (Engineering), PE (Petroleum), Executive Director and Chief Operating Officer
Wrixon F Gasteen BE (Hons), MBA (Dist), Non-executive Director
William J Dunmore BSc MSc, Non-executive Director
Robert Hubbard FCA, Non-executive Director
John T Wilson Bsc Msc, Non-executive Director
Peter S Moore PhD, BSc (Hons) MBA, Non-executive Director
GROUP GENERAL COUNSEL AND JOINT COMPANY SECRETARY
Daniel C M White LLB BCom LLM (Merit)
JOINT COMPANY SECRETARY
Joseph P Morfea
REGISTERED OFFICE
56-58 Jephson Street
Toowong
Queensland 4066
Telephone: +61 7 3181 3800
Fax: +61 7 3181 3855
www.centralpetroleum.com.au
AUDITORS
PricewaterhouseCoopers
123 Eagle Street
Brisbane
Queensland 4000
BANKERS
ANZ Banking Group
111 Eagle Street
Brisbane
Queensland 4000
SHARE REGISTER
Computershare Investor Services Pty Limited
117 Victoria Street,
West End
Queensland 4101
Telephone: +61 7 3237 2110
Fax: +61 3 9473 2085
www.computershare.com.au
STOCK EXCHANGE LISTING
Central Petroleum Limited shares are listed on the Australian Securities Exchange Limited under the code CTP.
2
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
CHAIRMAN’S LETTER
A MESSAGE FROM ANDY WHITTLE
Dear Fellow Shareholder
MAGELLAN (PALM VALLEY AND DINGO GAS FIELD) PURCHASE, OIL PRODUCTION FROM SURPRISE AND GAS FROM PALM
VALLEY, ENCOURAGEMENT AT MT KITTY-1, DRILLING IN GEORGINA, STAGE 2 OF SANTOS FARMOUT EXERCISED, FUTURE
SEISMIC AND DRILLING PLANNED.
Central’s ninth year since listing on the ASX has been challenging both financially and operationally for the Company in light
of the generally poor share price performance of small to medium market cap oil and gas exploration companies listed on
the ASX. As a Board we are very aware of the market and our financials and have not gone to shareholders to seek
additional funding during the past financial year despite the difficult times. We did however place 100 million shares with
large domestic institutions raising $10 million to part fund bringing the Surprise oil field into production and we have
recently secured a further placement of $6 million.
In September 2013 the Board decided to consolidate our share registry on a one for five basis. I believe we have stabilized
our share registry, are now more likely to gain institutional support in future capital raisings and this has made our shares
more attractive to the bigger end of the market.
The Board is confident that we are on the way to building a successful oil and gas company which is being positioned to
capitalize on the opportunities that are opening in the gas markets on the eastern seaboard. The predicted gas shortfalls
are well documented and we believe current fields and future discoveries in Central’s acreage will be key to meeting the
market.
I joined the Board in April 2012 and was appointed Chairman in April 2013. Over the past year we negotiated and
completed the purchase of Magellan’s Amadeus Basin assets which include the Palm Valley and Dingo gas fields. This
landmark purchase was paid for with shares and a cash component fully funded by Macquarie Bank, thereby moving us to a
producer of both oil and gas. This was a very significant turning point for our Company.
The required permits and pipeline licence to Alice Springs have been granted to allow Dingo Field development to
commence. The field development program is on track with first production expected to begin by mid 2015. Dingo is
entirely funded with facilities from Macquarie Bank.
It is not often that a super-major (company) like TOTAL will farm-in to acreage of companies like Central and fund grass
roots exploration. We are very excited to have them as partners and have benefited from their global knowledge in our
frontier Southern Georgina Basin acreage. We operated the 2D seismic that was successfully completed during the year.
We have commenced and are operating the drilling program which will hopefully find targets rich in unconventional shale-
gas worthy of flow testing.
Mt Kitty-1 was drilled during the year by SANTOS as part of its Stage 1 farm-in program to our Amadeus basin acreage. The
well encountered gas which was confirmed on wireline test and shown to contain significant Helium. Evaluation of the
potential of the fractured reservoir is still ongoing.
SANTOS then exercised its right to proceed to Stage 2 of its Amadeus farm-in which will result in a further 1,300 km of 2D
seismic being acquired in the Southern Amadeus area estimated to cost $12 million and earning SANTOS a 40%
participating interest.
During the year we surrendered the four permits we held in Western Australia on trend with Surprise as part of our formal
high-grading process. This decision was based on geological and geophysical studies that we conducted in house using new
aeromagnetic and gravity data that indicated the Surprise play did not extend as far west as we originally thought.
We hold areas with significant intra-field and near-field gas potential associated with Palm Valley and Dingo and other
prospectivity in held acreage which we believe will provide us with an opportunity to supply into the east coast gas market
shortfall.
Central also still holds extensive exploration acreage that we believe has considerable future exploration potential. For
example we hold most of the Wiso Basin and our explorationists are enthusiastic about this area following some recent in-
house work.
Whilst production from the Surprise West oil well is below initial expectations we are firm believers in further developing
the oil potential of the Amadeus Basin, but the advent of a gas market will lead us into the future.
3
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
CHAIRMAN’S LETTER
During the year Professor Peter Moore joined the Board following a career with Woodside from where he retired as
Executive Vice President Exploration. In addition we welcomed Tom Wilson who had a distinguished career with Apache
and Magellan as the Magellan Board nominee. Their experience has strengthened the technical and business skills of the
Board. Robert Hubbard joined the Board in December 2013 after a long career with PricewaterhouseCoopers as a partner.
Bill Dunmore and Mike Herrington are not standing for Board re-election at the next AGM. Mike will continue as Chief
Operating Officer which is a full time role now we have ongoing exploration, production and development. Bruce Elsholz
recently resigned as Joint Company Secretary and retires as Chief Financial Officer in November after 5 years of
distinguished service. Bruce has been replaced by Joseph Morfea as Company Secretary who is a seasoned professional and
came to us from Magellan. Leon Devaney will be the Company’s new Chief Financial Officer.
In addition we have made a number of senior management changes during the year to strengthen the Company for the
future. The Board carefully manages successfully succession planning at Board and senior management levels to ensure
orderly transitions occur.
We are moving from suburban Toowong into our new offices in 400 George Street in the city in early October 2014. This
move takes advantage of the well publicized excess supply of office space in Brisbane, consolidating our team in one office
and is being welcomed by the staff and will allow for the expected future growth of the Company.
Finally I would like to thank the Directors and in particular the Central team for their continued support during 2014 and
in particular for the efforts by Bill Dunmore, Mike Herrington and Bruce Elsholz. I am very pleased with the way the
Company is growing and on the degree of focus we have on the opportunities and challenges we face in the future.
Mr A. Whittle
Chairman
Melbourne,
30 September 2014
4
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
MANAGING DIRECTOR’S LETTER
Dear Fellow Shareholder,
This last year I am sure will be remembered as the year in which Central Petroleum turned the corner. The Company is
now poised to unlock the undoubted shareholder wealth that has been latent for so long. Santos has committed to Stage
2 of the Farm-in for the Southern Amadeus Joint Venture. Drilling at Mt Kitty has proved that the Southern Amadeus is
hydro-carbon charged and has helium to contribute handsomely to the economics of development. The drilling for the
Southern Georgina joint venture with Total has also commenced.
Underpinning this exploration, Central became both an oil and gas producer by April this year. Oil is being produced at
Surprise and gas is being produced at Palm Valley as a result of the acquisition from Magellan Petroleum. The Dingo Field
is being developed with the first gas expected to flow next year. Central reacquired the retention leases at Ooraminna. At
each of Palm Valley, Dingo and Ooraminna, Central has an interest in the under-explored acreage surrounding those
discoveries.
As the Company’s operations expanded, so too has our commitment to the economic future of the Traditional Owners.
Within 3 months of the Company becoming both an oil and gas producer we have over 30% of our production workforce
sourced from the local traditional owners.
Whilst aggressively growing oil production, exploration continues to be a cornerstone of our business strategy, and our
progress over the past 12 months has positioned the Company to take advantage of one of the most exciting (and energy
market transforming) infrastructure opportunities within Australia. We are now seeing a real opportunity to transition
from a small company with enormous exploration acreage within a constrained domestic gas market, to a company with
enormous acreage capable of supplying a large domestic market when that market is facing a gas shortage. We believe
this will have once-in-a-generation change in Australia’s domestic gas market, making for a more deep, liquid and
transparent pricing gas market which can only serve to benefit Australia’s gas users.
There has been substantial public commentary about the looming eastern seaboard gas shortage in the near future (3-5
years), initially in the financial press but now in the front pages of the mainstream press and government talking points.
The size of this problem means that the nation has no “silver bullet” solution. The national interest requires a lifting of the
exploration moratorium in NSW and Victoria, increased contribution from the Bass Strait and the Cooper Basin, shale gas
exploration, and for the Northern Territory supply to be connected to the eastern seaboard, optimally through Moomba.
Further, the addition of multi-sourced aggregated 6 trains of LNG to the Eastern Seaboard demand profile combined with
new and diverse gas resources within the NT create the economic conditions conducive to a major micro-economic
reform of the energy sector leading to the advent of a deep and liquid gas market.
In the past the absence of a deep and liquid market was a major barrier to the creation of a spot market. Without a spot
market, an explorer on discovery required to enter into a bilateral contract with a user or an aggregator. To get such a
contract, the explorer had to prove up sufficient reserves to cover the whole of the contract which required capital to be
expended prior to the entry into sales negotiations. With a deep and liquid market Australia can create a National
Balancing Point - an Australian benchmark like the “Henry Hub”.
The benefit for the exploration sector of such a development coupled with a pipeline from Alice Springs to Moomba,
cannot be overstated. The barriers to entry to the gas market for gas explorers – so high for so long – would be dismantled
immediately. The ensuing competitive forces create the right climate long term for Australia to have an internationally
competitive efficient gas market to the benefit of both gas consumers and suppliers.
Most importantly for explorers, access to market would no longer have to await the accumulation of sufficient reserves to
enable a bilateral long-term contract as the spot market would be able to consume any initial supply.
As a gas producer with significant reserve growth potential, Central is now positioned to be involved in causing this critical
piece of Australian energy infrastructure. Whilst we have no aspirations to own such a pipeline this has been a priority for
your Company. We are hopeful that our nation has the political will to embrace this huge productivity enhancing step.
Central will obviously benefit from such a development but so will the nation. Our focus to date is to position your
Company to take advantage of this nation-building reform.
Richard Cottee
Managing Director, Brisbane, 30 September 2014
5
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Your directors present their report on the consolidated entity, consisting of Central Petroleum Limited
(“Company” 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 2014.
Directors
The names of the directors of the parent company in office at any time during or since the end of the financial
year are:
Andrew P Whittle
Richard I Cottee
Michael R Herrington
Wrixon F Gasteen
William J Dunmore
Robert Hubbard (appointed 6 December 2013)
J.Thomas Wilson (appointed 31 March 2014)
Peter S Moore (appointed 14 April 2014)
Principal activities
The principal activity of the Consolidated Entity during the financial year was the exploration for and production
of hydrocarbons.
During the year the Consolidated Entity commenced oil production at Surprise and completed the acquisition of
both the Palm Valley Gas Field facility and the undeveloped gas reserves at Dingo. As a result the Consolidated
Entity now generates revenue from both oil and gas sales.
Operating result
The Consolidated Entity had an operating loss after income tax for the year ended 30 June 2014 of $10,857,986
(2013: loss of $9,283,393).
At 30 June 2014 consolidated cash and cash equivalents available totalled $10,330,474 (2013: $1,308,307),
including $1,590,386 (30 June 2013: $60,271) held in joint venture and $2,192,082 (30 June 2013: Nil) for Dingo
development.
Dividends
No dividends were paid or declared during the financial year (2013:Nil). No recommendation for payment of
dividends has been made.
Review of Operations
The Company’s focus for the year was as follows:
Acquiring the onshore Australian assets of Magellan Petroleum Australia Pty Ltd, specifically the Palm
Valley Gas Field and Facility and the undeveloped Dingo Gas Field.
Acquiring, processing and interpreting approximately 1,000 kms of new 2D seismic data and the
commencement of a drilling programme in the Southern Georgina Basin where Central (Operator) is in
joint venture with Total. This programme and associated evaluation work is ongoing and the Company
expects Phase 1 of the joint venture arrangements with Total will complete in 2016 when gross
exploration expenditures on the project reach approximately $90 million.
6
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
A free carried participant in the approximately 1,600 km 2D seismic programme in the Southern
Amadeus Basin and the drilling of the Mt Kitty gas well. Santos Limited is Operator for the farm-in
program.
Constructing the Surprise Oil Field Facilities and commencing oil production from the Surprise West
well.
Granted Petroleum Licences and Application Interests of Central Petroleum Limited
Acquisition of Palm Valley and Dingo Fields
The Company completed the purchase of the material onshore assets of Magellan Petroleum Australia Pty Ltd
(“the Magellan assets”) consisting primarily of the producing Palm Valley gas field and the undeveloped Dingo
gas field for $35 million. The deal closed on 31 March 2014. The consideration paid was $20 million cash and
approximately 39.5 million shares in Central.
The cash component was paid out of a loan facility with Macquarie Bank. The loan facility also includes a $30
million tranche for the development of the Dingo gas field and the construction of a 50km pipeline to Alice
Springs in order to service a gas sale contract with Power and Water Corporation of the Northern Territory.
Under the Macquarie Bank facility, Central granted 15 million unlisted options (to Macquarie) with an exercise
price of $0.50 and an exercise period of 30 months.
In addition to existing producing reserves, the acquisition includes significant in-place compression, processing
and transportation infrastructure at the Palm Valley field.
7
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Palm Valley Gas Field (OL3)
Northern Territory
(CTP - 100% Interest)
As a result of the acquisition of the Palm Valley Gas Field effective 1 April 2014 the Company commenced
receiving revenue from gas sales. This shifted Central from an explorer to a multi-field producer on both oil and
gas markets,
Gas production for the period 1 April 2014 to 30 June 2014 was 277,703 gigajoules(GJ).
Gas sales are per nominations received from the purchaser. The Field and the pipeline have capacity to produce
and deliver at higher volumes and the Company is looking to secure additional sales contracts.
Dingo Gas Field (L7) and Dingo Pipeline (PL30)
Northern Territory
(CTP - 100% Interest)
Dingo Gas Field (currently under development)
During the June 2014 Quarter the NT Government granted the Dingo Petroleum Production Licence (L7) to
Central. The production licence converts from the retention licence (RL2).
Subsequent to 30 June 2014, the Dingo Pipeline Licence (PL30) has been agreed with the Northern Territory
Department of Mines and Energy.
The Dingo Gas Field Development, which is solely funded under a $30 million tranche of the loan facility
agreement with Macquarie Bank, comprises construction of wellhead facilities, gathering pipelines, gas
8
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
conditioning facilities, a 50 km gas pipeline to Brewer Estate in Alice Springs, compression and custody transfer
metering facilities, and is designed to service a gas sale contract with Power and Water Corporation of the
Northern Territory.
Construction of the pipeline is well underway and is forecast to be completed before mid 2015 when first gas
sales to Power and Water Corporation in Alice Springs are scheduled to commence.
This strategic pipeline is a major milestone and signifies the start of the Company being a significant player in
the Northern Territory gas market. Over time Central looks forward to playing an important role in inter-
connecting Central Australia to the eastern seaboard gas network, possibly through Moomba.
Laying the Dingo Gas Pipeline near Alice Springs, Northern Territory
ATP 909, ATP 911, ATP 912
Southern Georgina Basin
Queensland
(CTP - 90% Interest) (farming out to Total E&P Australia)
Farmout
Following the completion of the seismic program in the Southern Georgina Basin the Company was able to re-
negotiate the framework for the Total farm-in. Stage 1 has been expanded both in the dollar amount (increase of
US$35 million) and the duration (to August 2015). Importantly the Company still remains liable for the last 20%
of the original stage 1 expenditure and then the last 20% of the increase. The increased expenditure in Stage 1
will allow for multi-zone production tests of some wells subject to satisfactory results from the initial Stage 1 core
hole exploration program.
Should Total continue and fulfil its funding obligations for Stages 2 and 3 Total will earn in increments to a total
of 68% in the permits.
Central is operating the farm-out areas for the first four years and after completion of Stage 3 Total will assume
operatorship for 90% of the area. Central will retain operatorship of the upstream activities on the remaining 10%
of the area.
9
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Drilling
Whiteley-1 well
Drilling commenced on 20 July 2014 at the Whiteley-1 unconventional gas exploration well in ATP 912.
Whiteley-1 is the first of a programme of unconventional gas exploration wells operated by Central and is being
drilled using Enerdrill Rig 2. The planned depth was 1,920 metres.
The primary objective is the Lower Arthur Creek Formation, which will be fully cored and sampled for gas
desorption and reservoir properties, in addition to an extensive logging program.
The well was drilled to around 1,150 metres which was a secondary target. As such when no petroleum was
encountered the decision was made to suspend the well pending the arrival of a liner to line the hole problems
and move immediately to Gaudi-1 and drill and complete that well before the start of wet season.
Gaudi-1 well
Gaudi-1 spudded on 14 September 2014 in ATP909. The planned depth is 2,900 metres. As with Whiteley-1 the
primary objective is the Lower Arthur Creek Formation.
Drilling Operations in the Southern Georgina Basin, Queensland
10
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Southern Amadeus Basin
Queensland
Various Permits, Retention Licences and Application Areas
(CTP – 75% to 100% Interest)
Santos Stage 2 Farmout
Under the farmout agreement, Santos was to fund exploration by investing an initial $30 million, with options
to invest a further $60 million in Stage 2 and a further $60 million in Stage 3. In return Santos would earn
rights to up to 70% of the area totalling nearly 80 thousand square kilometres. Santos assumed operatorship
during exploration and in the event that they are developed. Central will benefit from a free carry during the
farmout period.
The seismic acquisition program commenced July 2013. The program was intended to be around 1,800kms.
The amount acquired was 1,587kms over 7 permits in the Southern Amadeus area, with 300kms being
swapped out of Stage 1 and added to the original Stage 2 farmout phase.
In July 2014 Santos elected to proceed to Stage 2 of an amended Southern Amadeus Joint Venture with Central
under terms that will allow the JV to give priority to spending on areas of highest prospectivity.
Central has regained 100% ownership of the Ooraminna Gas Discovery in RLs 3 & 4 which will form a hub of
future opportunities to be pursued after the successful conclusion of a further gas sales contract. Central sees
great strategic merit in regaining control of RLs 3 & 4, particularly as RL3 is 10km from Central’s recently
acquired Dingo Gas Field and the 50km Dingo Pipeline currently under construction.
Central and Santos have concurred that the prospectivity of the Southern Amadeus has been confirmed by the
results of Mt Kitty and the 1,587km of 2D seismic acquired during Phase 1 of the farmout. As a result, an
additional 300km of seismic has been added to the current 1,000km of 2D seismic earmarked for the more
prospective Southern Amadeus following Central and Santos’ election not to proceed as a joint venture in the
Pedirka Basin (EPs 93 & 97).
The Santos farmout Stage 2 will therefore result in a further 1,300km of 2D seismic being acquired in the
Southern Amadeus area (estimated to cost around $12 Million) earning Santos 40% participating interest in
permits listed in the table below (the “Southern Amadeus Joint Venture”).
Central has been able to temporarily suspend its permit work commitments in the Pedirka Basin to enable it to
negotiate a more targeted acreage holding in that Basin. Following an extensive review of the data Central and
Santos has determined that the drilling of Pellinor was not the best use of capital and Central is looking forward to
concentrating on opportunities in EPs 93 & 97 now on a 100% basis.
Southern
Amadeus Area
Total Santos Participating Interest after
completion of Stage 1
Total Santos Participating Interest after
completion of Stage 2
EP82
EP105
EP106
EP107
EP112
EP(A)147
25%
25%
25%
25%
25%
25%
11
40% (ie additional 15% earned)
40% (ie additional 15% earned)
40% (ie additional 15% earned)
40% (ie additional 15% earned)
40% (ie additional 15% earned)
40% (ie additional 15% earned)
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
EP 125 – Northern Territory
(CTP-30% Interest, Santos [Operator]-70% interest on completion of Mt Kitty)
Mt Kitty Exploration Well
(Central is free carried for this well under the Santos farm-in arrangements)
In April 2014 the Company announced that it had been advised that the Mt Kitty exploration well flowed gas in
testing with flow rate of around 500,000 cubic feet per day through a 1-1/4” inch choke. The gas samplings also
included substantial Helium readings.
Wireline logging operations had commenced to evaluate the quality of the Heavitree Formation reservoir section
before an incident with the rig caused operations to be stopped. No persons were injured and there were no
environmental impact as a result of the incident. The well was secured for later re-entry.
The Operator advised the well was re-entered in early September and wireline logging was successfully
completed. Sidewall cores confirmed the previously reported gas flows were from granite basement. Raw
information indicates the basement is extensively fractured. The well has been plugged and suspended.
Full evaluation of well results and integration with seismic may result in a decision to drill an oriented sidetrack in
future, aiming to maximise intersection with observed fracturing.
Given the nearly 10% Helium detected in the sample which sells around $100/mcf (or nearly twenty times more
valuable than natural gas) Central has been evaluating the prospect of Helium extraction and sales at the well
head through relatively portable membrane technology. Early indications that even a relatively small field of
Helium of this quality can be quite economic.
Surprise West
Northern Territory
(CTP - 100% Interest)
Award of Production Licence 6 (“L6”) and
Surprise West production
In February 2014 Central was offered L6 for the Surprise Oil Field Development. This was the first Production
Licence offered in onshore Northern Territory since the passing of the Native Titles Act 1993 and was an
important milestone not only for Central but also for the Northern Territory and the Traditional Owners.
Initial production and storage facilities were installed to allow production to commence from the Surprise West
well in March 2014.
The installation of additional storage tanks and ancillary equipment followed. Storage capacity has increased to
5,000 barrels of oil storage with up to 2,000 barrels of water separation capacity.
The Surprise West well produced approximately 21,000 barrels of oil since commencing production in March
2014 to 30 June 2014. Unseasonally late wet weather in the region forced the closure of the access road to the
field for a considerable period of time in March/April period.
The Surprise West well continues to produce around 180 bopd which is below initial expectations but remains a
valuable cash-flow contribution to the Company. Currently the oil is trucked to Port Bonython in South Australia
where it is stored prior to its export by tanker, normally to refineries in Singapore.
Central is actively pursuing market opportunities for domestic use whilst also concentrating on obtaining
efficiencies in its transportation costs.
12
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Exploration Application Areas, Northern Territory
Amadeus, Pedirka and Wiso Basins - Various Areas (see Table on Page 93)
The Company continued to evaluate a number of these areas and has been working to gain Native Title
clearance and secure the other necessary approvals in advance of award of exploration permit status.
Exploration Application Areas, Amadeus Basin, Western Australia
Areas 16/08-9, 17/08-9, 18/08-9 and L12-2
Subsequent to 30 June 2014, the Company has withdrawn from these application areas.
Reserves Information
The Company has no certified oil and gas reserves as defined by the Australian Stock Exchange but intends
to certify its producing wells in the next 12 months after Dingo goes onto production.
Operating and Financial Review
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.
By its nature exploration is an extremely high risk business. Most exploration activity, in particular seismic and
drilling is conducted in joint venture, 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
environment. In addition, as with most businesses there is also market risk, product pricing risks and foreign
exchange risk. Exploration is typically funded with risk capital. Debt capital is normally only available for
development activities such as facility and pipeline construction.
Crude oil prices are benchmarked against a series of global pricing points, such as WTI, Brent and Tapis. Over
the last five years crude oil, unlike most other commodities, has been extremely resilient to large swings in the
market price. There is a spot market for oil and producers enjoy a relatively secure position on price for their
product.
Business Strategy
Gas producers in Australia currently do not have a comparable spot market mechanism for their gas. Gas is
generally sold under long term contracts. However, Central is of the view that there is an emerging push by
Federal, State and Territorial governments for the near term (3 to 5 years) construction of additional gas
pipelines to link into existing pipeline infrastructure and form a national grid for Australia. This will provide large
and new markets for the estranged gas fields, present and future, in the Northern Territory and elsewhere. As a
gas producer the Company is planning to be a part of this exciting “game changer”.
Central will however continue to also explore for oil as it is a valuable source of revenue as well as being a risk
spreading in the event the gas strategy falters. The Company is also investigating opportunities to produce and
sell Helium.
Key financial and operating data
The following table and discussion is a one year (and five year) comparative analysis of the Consolidated
Entities’ 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.
13
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
2014
$Mill.
3.72
4.66
10.86
24.97
46.27
(23.77)
43.07
3.26
267,328
17,489
51
2013
$Mill.
-
6.98
9.28
7.56
1.28
-
24.65
4.93
-
-
26
2012
$Mill.
-
18.72
26.36
23.60
1.78
-
24.20
10.64
-
-
17
2011
$Mill.
-
31.34
36.64
5.90
0.83
-
25.90
12.14
-
-
19
2010
$Mill.
-
8.17
11.81
24.52
0.45
-
56.51
46.27
-
-
20
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)
No of employees at 30 June
The 2014 year represents a milestone for Central as the company is now generating revenues from oil and gas.
Oil production commenced at the Surprise Field in late March 2014. As a result of purchasing the producing
Palm Valley Gas Field effective 31 March 2014 with an associated gas contract, the Company is also generating
gas revenues.
Road Tanker collecting crude oil at Surprise
The Company recorded $3.2 million of operating revenue for the 2014 year. The existing purchaser of Palm
Valley gas is scheduled to increase its nominations during 2015 and the currently undeveloped Dingo Gas Field
is scheduled to provide gas into a new contract around the time the Dingo pipeline is completed, expected mid
2015. The Company will also actively seek out new gas sales opportunities. Oil production will continue from
Surprise.
Exploration expenditure fluctuates year over year depending on activity levels, particularly with seismic and
drilling costs. The fluctuations are even more pronounced for the smaller pure explorers like Central as their
funding comes from the equity markets which over the last 2 to 3 years have essentially dried up for resource
stocks. With onshore wells in central Australia costing between $10 million to $15 million per well, securing joint
venture partners is critical to an active, meaningful exploration program. In 2013 Central completed two
substantial farmout deals, one with Santos and another with TOTAL.
14
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
In addition to the exploration expenditure booked by the Company ($4.66 million in 2014) it is important to note
that approximately $40 million was expended on exploration permits in which Central has a substantial and
majority working interest in the year ended 30 June 2014.
From the table, it is noteworthy that Central’s exploration spend for the 2011 and 2012 years was $63 million.
This represents one regional seismic programme and three wells, funded 100% by the Company. With a change
of management around 30 June 2012 this business model was changed to a more “risk spreading” approach.
‘Loss before income tax for the Year’ for Central is largely driven by the level of exploration expenditure.
Central’s accounting policy has consistently been to expense its exploration costs on an annual basis. Many
other companies, particularly the smaller explorers, adopt the more conservative accounting policy of carrying
forward those exploration costs on their balance sheets and then expensing at defined future points in time.
The significant change in the Company’s Balance Sheet between 30 June 2013 and 30 June 2014 reflects the
major acquisition transaction which saw Central acquire the onshore Australian assets of Magellan Petroleum
(‘Magellan’), being the Palm Valley Gas Field and Facility and the undeveloped Dingo Gas Field.
The asset purchase price was $35 million with a $20 million cash consideration and $15 million of equity issued
to Magellan. The cash component was funded out of a $50 million project facility arranged with Macquarie Bank.
The $30 million development component of the financing facility is primarily to fund the development of the
Dingo field and construction of the Dingo gas pipeline. At 30 June 2014 Central had drawn down $3.77 million
of that facility, and this along with the $20 million ($23.77 million in total) is recorded on the balance sheet as
Borrowings. The acquired assets are recorded in the financial records using the “business combination”
accounting policy and form part of the balance sheet asset “Property, plant and equipment”.
Equity issued during the 2014 year was $25 million, comprising the $15 million of shares issued to Magellan and
a $10 million share placement for cash in July 2013. Central recently completed a $6 million placement for cash.
Net working capital is the excess of current assets over current liabilities. For an explorer cash is usually the
major component of current assets. The recent $6 million share placement has bolstered Central’s liquidity.
The increase in the staff head count to 51 at 30 June 2014 compared to 26 at 30 June 2013 primarily reflects the
acquisition of the Magellan assets including field staff at the Palm Valley Gas Plant and a portion of their
Brisbane based staff. In addition staff have been added at the Surprise Field location. A number of the staff
increases in these field locations are Traditional Owners.
Information on directors
Andrew P Whittle BSc (Hons)
Independent Non-Executive Chairman¹,3,5
Mr Whittle has around 45 years of technical and managerial experience in the petroleum exploration and
production industry with a focus on South East Asia and Australia. His experience includes over 21 years with
several affiliates of Exxon Corporation in Australia, Singapore, Malaysia, Canada and the US, finally in the
position of geological manager of Esso Australia. Thereafter, he was exploration manager for 5 years with GFE
Resources Ltd, Australia. He has over 15 years’ experience through PetroVal Australasian Pty Ltd, of which he
is a founding director, and his private consulting company Sheristowe Pty Ltd, in preparing independent
technical reports and in evaluating exploration and production assets and providing valuations, and expert
opinions for a range of clients. He was closely involved in the exploration that led to the identification and
discovery of the Thylacine gas field in the Otway Basin and in promoting Pexco into Indonesian deepwater
exploration. He is also a member of the American Association of Petroleum Geologists, and the Petroleum
Exploration Society of Australia.
Mr Whittle stepped down as a director of Malaysia listed Bumi Armada Sdn Bhd, a major offshore service
company in June 2014, a role he held since June 2011. He is currently a non-executive director of ASX listed
Bass Strait Oil Ltd. Within the last three years, he has not been a director of any other listed public company.
15
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Richard I Cottee BA LLB (Hons)
Managing Director and Chief Executive Officer 3
With a background in law and energy, Mr Cottee is a prominent figure in the Australian oil and gas industry
having taken QGC from an early stage explorer to a major unconventional gas supplier sold to BG Group for
$5.7 billion.
Mr Cottee has renowned international energy experience with an outstanding reputation for driving company
market development. A lawyer, Mr Cottee has also served as the director of marketing and sales for Cyprus
Amax and then was named managing director of England, Wales, Scotland, Ireland and the Scandinavian and
Norway regions for NRG Energy. Previously he worked with Santos Oil and Gas. He was also chief executive
officer of CS Energy Ltd, a Queensland Government owned electricity generator.
Mr Cottee is currently a non-executive chairman of Austin Exploration Limited and is a principal of Freestone
Energy Partners Pty Ltd (“FEP”). Within the last three years, he has not been a director of any other listed public
company.
Michael R Herrington BSc (Engineering), PE (Petroleum)
Executive Director and Chief Operating Officer 7
Mr Herrington was recently upstream president for QGC, a BG Group Company, managing director for Jabiru
Energy and previously was managing director for Enron Exploration Australia Pty Ltd based in Queensland,
Australia and Enron Oil & Gas China Ltd based in Beijing, China. Mr Herrington has more than 30 years of
diversified petroleum industry experience, holds a BS degree in civil engineering from the University of Utah and
is a registered professional engineer. He has set up operations in Spain, France, Australia as well as China.
These efforts have been consistently results orientated and have been completed on time and under budget
invoking state of the art technology and developing new concepts where necessary incorporating such diverse
technologies as satellite imaging and drilling rig modifications. In particular he has managed efforts to establish
coal bed methane recovery leases in Europe, Australia and Asia.
Within the last three years, Mr Herrington has not been a director of any other listed public company.
Wrixon F Gasteen BE (Hons), MBA (Dist)
Independent Non-Executive Director ²
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. Previously Mr Gasteen was chief executive officer
of Hong Leong Asia (HLA) where he presided over the transformation and rapid development of the company by
both acquisition and organic growth, from a loss making South East Asian building materials company with
$300m in annual sales to $2.2bn in annual sales. He was director of Tasek Corporation (cement) (KLSE) and
also chairman and president of China Yuchai International (diesel engines) listed on the New York Stock
Exchange (NYSE).
In March 2014 Mr Gasteen joined the board of ASX listed Sino Australia Oil & Gas as a non-executive director.
Within the last three years, Mr Gasteen has not been a director of any other listed public company.
William J Dunmore BSc MSc
Independent Non-Executive Director 7
Mr Dunmore is an experienced reservoir and production engineer with significant transaction, analysis and
financial modelling knowledge from consulting and employment with a number of petroleum companies and
financial institutions including Barclays Bank, Unicredit, HVB, British Gas, HBOS/BankWest, SMBC, BHP
Petroleum, Schlumberger, Hardman, Mobil, Petrobras, Total, Nippon Oil and Powergen.
Mr Dunmore has over 35 years of direct relevant experience in Australia, Europe and elsewhere. He actively
consults to a number of clients. Recent and current projects have included several very large gas and LNG
developments in Asia and Australia as well as oil and gas projects located around the world. He has also
advised on asset finance such as drilling rig conversions and FPSO new build and construction. He is a member
of the Society of Petroleum Engineers.
Within the last three years, Mr Dunmore has not been a director of any other listed public company.
16
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Robert Hubbard FCA
Independent Non-Executive Director,1,4
Mr Hubbard was a partner with PricewaterhouseCoopers for 22 years specialising in audit, deals and valuation
advice specialising in the resources sector. He has highly developed financial skills and business experience
including managing significant capital and growth agendas, risk management, best practice corporate
governance and valuations.
Mr Hubbard is a non-executive director of Bendigo and Adelaide Bank Limited as well as ASX and TSX listed
Orocobre Limited. Within the last three years, he has not been a director of any other listed public company.
John Thomas (Tom) Wilson, BSc (Zoology) MSc(Geology)
Non-Executive Director
Mr Wilson began his career as a geologist with Shell Oil Company before joining Apache Corporation, where he
held various management positions and led Apache’s entry into international markets. Subsequent to Apache,
Mr Wilson served as president of Anderman International, which developed the Chernogoskoye Field in western
Siberia. Mr Wilson joined the management team of Yamal Energy Partners, which developed the South Tambay
Field, possibly the first Russian-led LNG project in the Russian Republic, which was later sold to Gazprom.
Mr Wilson was appointed a director of US based Magellan Petroleum Corporation in 2009 and the Company’s
CEO in 2011. Within the last three years, he has not been a director of any other listed public company.
Dr Peter S Moore PhD BSc (Hons) MBA
Independent Non-Executive Director 3, 6
Dr Peter Moore has over thirty years of experience in the oil and gas business. His career includes roles with the
Geological Society of Western Australia, Delhi Petroleum Pty Ltd, the exploration operator of the Cooper Basin
consortium in South Australia and Queensland, Esso Australia, Exxon Exploration Company in Houston and
from 1998 until his retirement in 2013, with Woodside Energy Ltd.
At Woodside Energy Peter held various roles including most recently 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 Chair of the Curtin Graduate School of Business Advisory Board and a Member of the Elsevier Oil &
Gas Advisory Board. Within the last three years, he has not been a director of any other listed public company.
¹ Member of the audit committee
² Chairman of the audit committee
3 Member of the remuneration committee
4 Chairman of the remuneration committee
5 Member of the nominations committee
6 Chairman of the nominations committee
7 Member of the nominations committee up to 30 June 2014
Company secretaries
Daniel CM White LLB BCom LLM (Merit)
Mr White is an experienced oil & 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
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 most recently Chief Financial Officer of Magellan
Petroleum Australia Pty Ltd, a wholly owned subsidiary of Denver based Magellan Petroleum Corporation. Prior
to Magellan Mr Morfea worked for Santos Limited and Theiss Dampier Mitsui Coal Pty Ltd.
17
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Directors’ meetings
The number of directors’ meetings held where the director was eligible to attend and the number of meetings
attended by each of the directors of the Company during the financial year were:
Full Meeting
of Directors
Number of
meetings
eligible
Number of
meetings
attended
Audit
Committee
Remuneration
Committee
Number of
meetings
eligible
Number of
meetings
attended
Number of
meetings
eligible
Number of
meetings
attended
Nominations
Committee
Number of
meetings
eligible
Number of
meetings
attended
Andrew Whittle
Richard Cottee
William Dunmore
Michael Herrington
Wrixon Gasteen
Robert Hubbard
Tom Wilson
Peter Moore
6
6
6
6
6
3
1
1
6
6
6
6
6
3
1
1
3
nil
nil
nil
3
1
nil
nil
3
nil
nil
nil
3
1
nil
nil
1
nil
nil
nil
nil
1
nil
1
1
nil
nil
nil
nil
1
nil
1
nil
1
1
1
nil
nil
nil
nil
nil
1
1
1
nil
nil
nil
nil
Realised Remuneration of Directors and Key Management Personnel for the 2014 Year
The Directors consider the remuneration information contained within the tables presented in the statutory
remuneration report (pages 21 to 32) may give a distorted view of the true remuneration realised by the directors
and key management personnel for the 2014 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
Andrew Whittle
William Dunmore
Wrixon Gasteen
Robert Hubbard2
Thomas Wilson3
Peter Moore4
Sub-total
Executive
Directors & Key
Management
Personnel
Richard Cottee5
Michael Herrington
Daniel White
Bruce Elsholz
Leon Devaney
Michael Bucknill
Robbert Willink
Sub-total
Total
Remuneration
Salary/
fees
$
101,666
94,476
75,000
40,265
16,250
16,042
343,699
Non-
monetary
1
benefits
$
11,707
-
13,008
-
-
-
Superannuation
contributions
$
9,404
-
-
3,724
-
1,484
24,715
14,612
Amount
$
122,777
94,476
88,008
43,989
16,250
17,526
383,026
% of
TRP
100%
100%
100%
100%
100%
100%
100%
Value of LTI
Grant that
Vested
$
-
-
-
-
-
-
-
Actual Total
Remuneration
Package
(TRP)
$
122,777
94,476
88,008
43,989
16,250
17,526
383,026
580,005
587,995
432,155
303,728
311,241
321,663
340,236
2,877,023
-
11,707
-
-
-
-
-
11,707
22,945
33,068
26,693
27,689
29.180
27,651
29,116
196,342
602.950
632,770
458,848
331,417
340,421
349,314
369,352
3,085,072
100%
100%
92%
91%
91%
100%
100%
97%
-
-
42,534
33,060
32,480
-
-
108,074
602,950
632,770
501,382
364,477
372,901
349,314
369,352
3,193,146
3,220,722
36,422
210,954
3,468,098
97%
108,074
3,576,172
1 Fringe benefits tax
3 Appointed 31 March 2014
5 Mr Cottee’s services are provided by Freestone Energy Partners (“FEP”). Mr Cottee has a 50% beneficial equity interest in FEP
2 Appointed 6 December 2013
4 Appointed 14 April 2014
18
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Significant changes in the state of affairs
Significant changes in the state of affairs of the Consolidated Entity during the financial year were as follows:
• Acquired the Palm Valley Gas Field and Production Facilities and the undeveloped Dingo Gas Field
from Magellan Petroleum Corporation for $35 million, comprising $20 million cash and $15 million of
Central share capital.
• Entered into a $50 million debt facility with Macquarie Bank Limited. The facility comprises $20 million
for the cash component of the purchase price to acquire the Palm Valley and Dingo assets and up to
$30 million of development capital for the Dingo Field and pipeline.
• Magellan Petroleum Corporation became Central’s largest shareholder with 39,473,684 shares which
represents 11.32% of the Company’s equity at 30 June 2014.
•
There was approximately $45 million (gross) of exploration expenditure on Central’s acreage in the year
ended 30 June 2014, including through joint ventures with Santos and Total E&P.
• Commercial oil production from the Surprise Field commenced in March 2014.
Matters subsequent to the end of the financial year
(i) Decision on Legal Matter with John Heugh
On 5 September 2014 the Court found that it was not reasonable for the board to terminate Mr Heugh’s contract
and awarded him damages of $1,598,298 inclusive of interest. $1,000,000 of the claim is covered pursuant to
the Company’s Employment Practices Liability insurance.
More details of the decision are contained on page 20 of the Directors’ Report.
(ii) Share Placement
On 24 September 2014 the Company agreed to place 20 million shares at $0.30 per share with institutional
investors in Australia and Hong Kong raising $6 million.
Other than the above, no matters or circumstances, have arisen since the end of the financial year which
significantly affected or may affect the operations of the Consolidated Entity, the results of those operations or
the state of affairs of the Consolidated Entity in future financial years.
Refer also to note 34 to the Consolidated Financial Statements.
Likely developments and expected results of operations
Exploration will continue in both the Amadeus and Southern Georgina Basins in the search for commercial
accumulations of hydrocarbons. Gas, from both conventional and unconventional sources, will remain Central’s
primary target in the near to mid-term. The Company’s 100% owned gas pipeline connecting the Dingo gas field
to Alice Springs is expected to be completed in the first half of the 2015 calendar year. As a result, Dingo gas will
be supplying a new sales contract which is already in place. Deliveries under that contract will commence
concurrently with the commissioning of the pipeline. Additional gas sales contracts for both Dingo and Palm
Valley gas will be sought. Both fields have available capacity as does the existing pipeline infrastructure in the
Northern Territory.
Oil sales from the Surprise West -1 will continue to provide a valuable contribution to the funding of Central’s
working capital requirements. The cash netback per barrel is key and the Company will look to alternative sales
opportunities as well as improved cost efficiencies both at the field and with transportation costs. Production
from a second oil well nearby to Surprise West-1 would incur minimal additional field operating expenses and
there is expected to be transportation efficiencies. The economics of a second well continue to be monitored.
The prospect of an interconnect of Northern Territory gas to the large gas hungry markets on the eastern
seaboard of Australia through a pipeline which is currently under active consideration, has the potential to
radically enhance the economics of exploration effort. Central with its significant reserve growth potential in
central Australia and in particular in the Northern Territory is well positioned to participate and benefit from such
a pipeline.
19
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Environmental regulation
The Consolidated Entity is subject to significant environmental regulation with regard to its exploration activities.
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 51 employees at 30 June 2014 (26 at 30 June 2013).
Proceedings on behalf of the Company
Except as referred below no person has applied for leave of Court to bring proceedings on behalf of the
Company or intervene in any proceedings to which the Company is a party for the purpose of taking
responsibility on behalf of the Consolidated Entity for all or any part of those proceedings. The Consolidated
Entity was a party to the following proceedings during the year.
Legal Action with John Heugh
In March 2012 the Company advised that it had terminated the employment of Mr John Heugh. Mr John Heugh
commenced an action in the Supreme Court of Western Australia against the Company disputing the
Company's termination of his employment.
Mr Heugh has also brought an action in the Supreme Court of Western Australia against the Company and
others for alleged false and defamatory statements of and concerning Mr Heugh.
Decision on Termination of Employment
On 5 September 2014 Mr Justice Le Miere handed down his judgement on the case alleging unfair dismissal of John
Heugh by the board of Central Petroleum in the first quarter of 2012.
The Court found that Mr Heugh seriously breached his employment contract by failing to comply with the directions of
the board by putting pressure on its then Exploration Manager not to accept responsibility for farmouts, and by failing to
ensure the proper implementation of Central Petroleum’s policies, procedures and systems and in particular its code of
conduct. However, the Court held that Mr Heugh remedied those breaches.
The Court found that it was not reasonable for the board to terminate Mr Heugh’s contract and awarded him
damages of $1,598,298 inclusive of interest. $1,000,000 of the claim is covered pursuant to the Company’s
Employment Practices Liability insurance.
The Company will not initiate an appeal of this decision and has paid the proportion of the damages not covered by
insurance to the plaintiff.
Defamation Case
No hearing date has yet been set for the defamation case.
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.
20
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
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
Tax compliance
(ii) Other services
Corporate advisory – due diligence
Remuneration benchmarking
Forensic services
Total remuneration for non-audit services
Auditor’s Independence
2014
$
82,266
82,226
181,607
10,000
-
191,607
273,873
2013
$
83,209
83,209
-
12,500
20,240
32,740
115,949
The directors received an Independence Declaration from the auditor of Central Petroleum Limited as required
under section 307C of the Corporations Act 2001 and this is set out on page 33.
Remuneration report
This remuneration report, which has been audited, outlines the remuneration arrangements in place for directors
and other key management personnel of the Consolidated Entity.
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
Andrew Whittle
Richard Cottee
Non –Executive Chairman
Managing Director and Chief Executive Officer
William Dunmore
Non-Executive Director
Michael Herrington
Executive Director and Chief Operating Officer
Wrixon Gasteen
Robert Hubbard
Non-Executive Director
Non-Executive Director
J.Thomas Wilson
Non-Executive Director
Peter Moore
Non-Executive Director
Appointed 6 December 2013
Appointed 31 March 2014
Appointed 14 April 2014
Other Key Management Personnel
Bruce Elsholz
Daniel White
Leon Devaney
Robert Willink
Chief Financial Officer and Company Secretary 1
Group General Counsel and Company Secretary
Chief Commercial Officer 2
Exploration Advisor
Michael Bucknill
¹ Resigned as Company Secretary effective 25 August 2014 and has given notice of his resignation as Chief Financial Officer.
2 To be appointed Chief Financial Officer effective 31 October 2014.
General Manager Exploration
21
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Remuneration Policy
Proposed Changes from July 2014
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 exploration industry. Accordingly, the Company is currently
revamping its remuneration practices and in particular its short term and long term incentive plans with 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). These changes are to be effective from 1
July 2014. It is intended that the long term incentive plan (LTIP) will be put to a shareholder vote at the 2014
Annual General Meeting to be held in November 2014. More complete details of the plans will be provided in the
Notice of Meeting to Shareholders and in subsequent annual reports of the Company.
Remuneration Consultants
In 2014 the Board engaged PricewaterhouseCoopers to provide guidance on current industry practice for
remunerating senior executives. The results were presented to the Chairman of the Board for consideration. A
fee of $10,000 was paid for this service. During the engagement the consultant liaised directly with the Chairman
and management was only involved to the extent of providing factual information.
In 2014 the Remuneration Committee engaged RMBN Pty Ltd to carry out a review of the proposed STIP and
LTIP plans and to provide an opinion as to how such a proposed plan would be viewed by proxy advisors and
institutional investors. A fee of $19,500 was paid for this service. During this engagement the consultant liaised
directly with the Chair of the Remuneration Committee and management was only involved to the extent of
providing factual information.
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 ended on 30 June 2014 the remuneration of directors and executives consisted of the
following key elements:
Non-Executive Directors
Fees including statutory superannuation;
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
Annual salary and non-monetary benefits including statutory superannuation;
Participation in outcomes based bonuses over and above salary arrangements;
Participation in an incentive option scheme;
There is no guaranteed base pay increases included in any executive’s contract.
From 1 July 2014 the outcomes based bonus arrangement will be replaced by a performance based plan
comprising a matrix of corporate, departmental and individual key performance indicators (KPI’s) for all eligible
employees. The Company’s Board of Directors will determine the maximum amount of KPI achievable in any
year (normally expressed as a percentage of base salary). Achieving that maximum is contingent upon all of the
KPI’s in the matrix being met at the 100% level. The KPI’s will be 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, STI payments will be limited to a maximum of
10 % of base salary in 2014/15.
Effective for years commencing 1 July 2014 onwards and subject to shareholder approval the Company will
implement a share based LTIP to incentivise eligible employees. The proposed delivery instrument will be
performance rights. The Company will make annual grants under this plan. The maximum number of
performance rights granted in any year will have a value equivalent to a percentage of base salary. The actual
22
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
number of performance rights granted in any year will be determined by measuring CTP’s share price
performance over that year compared to a peer group of companies (a relative measure) and compared to its
absolute share price movement over a 3 year cycle. Non-executive directors will not be eligible to participate in
the LTIP. The LTIP will also include all other aspects considered appropriate to make the LTIP contemporary.
Subject to shareholder approval of the proposed new LTIP, the Company does not expect to be granting any
further options to employees or directors under the Company’s 2012 Share Option Plan for Directors and
Employees.
Outcomes based bonus scheme
Participation in the bonus scheme is at the discretion of the board of directors. In determining the extent of any
outcomes based bonus, the Company takes into consideration the objectives of the Company, as the Company
may set from time to time, and any other matter that it deems appropriate.
The outcomes will vary each year. In certain years there may be no outcomes achieved that merit a bonus. In
2014 the outcomes for which a bonus pool was allocated were the successful closing of the acquisition of the
Magellan assets and the closing of the Financing Facility with Macquarie Bank, and the successful renegotiation
of Phase 1 of the farm-deal with TOTAL which expanded both the dollar amount (increase of US$35 million) and
the duration (to August 2015).
Incentive Option Schemes
On 19 July 2012 shareholders approved 172,922,033 options (34,584,407 after the 1 for 5 securities
consolidation) be issued to FEP on 8 August 2012 exercisable at $0.09 ($0.45 after the 1 for 5 securities
consolidation) subject to the satisfaction of various market price vesting hurdles. Mr Richard Cottee has a
beneficial equity interest in FEP. On 29 November 2012 shareholders approved the grant of 20,500,000 options
(4,100,000 after the 1 for 5 securities consolidation) to various directors exercisable at $0.09 ($0.45 after the 1
for 5 securities consolidation) subject to various market price vesting hurdles. Neither the options issued to FEP
or to the directors have any performance hurdles.
On 28 November 2013 shareholders approved the grant of 1,800,000 options to Mr Michael Herrington
exercisable at $0.475 subject to the satisfaction of various vesting hurdles. During the year ended 30 June 2014
employees were granted 21,896,680 options (4,379,336 after the 1 for 5 securities consolidation) exercisable at
$0.09 ($0.45 after the 1 for 5 securities consolidation) and 207,000 options exercisable at $0.65, all subject to
various market price vesting hurdles. No options were granted to employees under the incentive option scheme
during the year ended June 2013.
In addition to the market price vesting hurdles the options issued to employees and to Executive Director Mr
Michael Herrington also have performance hurdles. The matrix is 80% of the options are subject the satisfying
key performance indicators (a combination of personal, departmental and corporate) with the remaining 20%
subject to continued employment.
Details of the options granted to Mr Michael Herrington and key management personnel are included in table 5
(page 29) of this remuneration report. No other director received options under the Incentive Option Scheme
that contained any performance criteria in respect of their vesting.
23
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Details of remuneration
Details of the remuneration of the directors and the key management personnel of Central Petroleum Ltd and
the Consolidated Entity are set out in the following tables. Details of realised remuneration appear on page 18.
Table 1: Remuneration of Directors and Key Management Personnel
Short-term
Post-employment
Long-term
benefits
Share-
based
payments
Salary/
fees
$
Non-monetary
benefits
$
1
Superannuation
contributions
$
Term’tion
Benefits
$
Long
service
leave
$
(At Risk)
Options 12
$
Total
$
Value of
options as
proportion
of
remuneration
%
Non-Executive Directors
Andrew Whittle
William Dunmore
Wrixon Gasteen
Henry Askin2
Robert Hubbard3
Thomas Wison4
Peter Moore5
2014
2013
2014
2013
2014
2013
2014
2013
2014
2013
2014
2013
2014
2013
2014
2013
101,666
87,500
94,476
67,500
75,000
75,000
-
41,667
40,265
-
16,250
-
16,042
-
343,699
271,667
11,707
4,489
-
-
13,008
4,991
-
6,484
-
-
-
-
-
-
24,715
15,964
9,404
6,375
-
-
-
-
-
3,750
3,724
-
-
-
1,484
-
14,612
10,125
Executive Directors and Other Key Management Personnel
Richard Cottee11
Michael Herrington10
Daniel White
Bruce Elsholz
Leon Devaney
Michael Bucknill6
Robbert Willink7
Dalton Hallgren8
Trevor Shortt9
Sub-total
Total
Remuneration
2014
2013
2014
2013
2014
2013
2014
2013
2014
2013
2014
2013
2014
2013
2014
2013
2014
2013
2014
580,005
577,785
587,995
380,339
432,155
433,139
303,726
267,852
311,241
175,180
321,663
-
340,236
-
-
247,126
-
306,339
2,877,023
2013
2,387,760
2014
3,220,721
2013
2,659,427
-
-
11,707
4,489
-
-
-
-
-
-
-
-
-
-
-
-
-
-
11,707
4,489
36,421
20,453
22,945
21,630
33,068
24,229
26,693
30,150
27,689
22,385
29.180
15,766
27,651
-
29,116
-
-
18,388
-
29,700
196,341
162,248
210,954
172,373
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
118,392
69,224
-
-
131,547
76,915
-
99,990
-
-
-
-
-
249,939
246,129
7,536
3,377
6,298
2,067
10,014
9,961
7,520
9,598
3,837
1,133
2,560
-
2,816
-
-
(1,551)
-
(2,171)
40,581
1,887,313
1,784,181
118,392
69,224
3,733
-
2,622
-
2,576
-
2,000
-
2,400
-
-
9,461
-
20,086
2,019,036
241,169
167,588
94,476
67,500
219,555
156,906
-
151,891
43.989
-
16,250
-
17,526
-
632.965
543,885
2,497,799
2,386,973
757,460
480,348
472,595
473,240
341,557
299,835
346,834
192,079
353,874
-
374,568
-
-
273,424
-
353,954
5,144,688
22,404
1,882,952
4,459,853
40,581
2,268,975
5,777,652
22,404
2,129,081
5,003,738
49%
41%
0%
0%
60%
49%
-
66%
0%
-
0%
-
0%
-
39%
45%
76%
75%
16%
14%
1%
0%
1%
0%
1%
0%
1%
-
1%
-
-
3%
-
6%
39%
42%
39%
43%
1 Represents fringe benefits tax. Directors and Officers Liability Insurance
premiums have been removed from the 2013 comparatives.
3 Appointed 6 December 2013
5 Appointed 14 April 2014
7 Appointed 1 July 2013
9 Resigned 29 June 2013
11 Freestone Energy Partners Pty Ltd (“FEP”) have provided the services of Richard Cottee on the basis of a secondment. As such compensation is made to FEP
in line with Richard Cottee’s service agreement shown on page 31. Richard Cottee has a 50% beneficial equity interest in FEP.
12 The valuation date for options issued to FEP was 19 July 2012 and to directors was 29 November 2012.
4 Appointed 31 March 2014
6 Appointed 1 July 2013
8 Resigned 31 January 2013
10Appointed Chief Operating Officer 31 January 2013
2 Retired 30 November 2012
24
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Details of remuneration (continued)
The fair values of options granted during 2014 were independently valued. The values are calculated at the dates
of grant using a Binomial valuation model. The values are allocated to each reporting period evenly over the
period from grant date to vesting date.
The values disclosed for 2014 are the portions of the fair values applicable to and recognised in this reporting
period. The following factors and assumptions were used in determining the fair value of options at grant date:
Grant
date
Expiry
date
Fair value
per option
Exercise
price
Price of
shares at
grant date
Estimated
volatility
Risk free
interest rate
Dividend
yield
10 Jul 13
15 Nov 15
$0.0471
$0.451
$0.631
60% to 90%
2.73%
28 Nov 13 15 Nov 17
$0.045
$0.475
$0.32
45% to 65%
2.69%
1 Values adjusted to reflect the 1 for 5 consolidation of all Company securities at 30 September 2013
-
-
The values disclosed for 2013 are the portions of the fair values applicable to and recognised in this reporting
period. The following factors and assumptions were used in determining the fair value of options at grant date:
Grant
date
Expiry
date
Fair value
per option1
Exercise
price1
Price of
shares at
grant date1
Estimated
volatility
Risk free
interest rate
Dividend
yield
19 Jul 12 15 Nov 15
$0.235
19 Jul 12 15 Nov 17
$0.270
19 Jul 12 15 Nov 17
$0.245
29 Nov 12 15 Nov 15
$0.385
29 Nov 12 15 Nov 17
$0.420
$0.45
$0.45
$0.45
$0.45
$0.45
$0.625
60% to 90%
2.73%
$0.625
60% to 90%
2.77%
$0.625
60% to 90%
2.77%
$0.755
50% to 80%
2.73%
$0.755
50% to 80%
2.77%
29 Nov 12 15 Nov 17
$0.400
$0.45
$0.755
50% to 80%
2.77%
1 Values adjusted to reflect the 1 for 5 consolidation of all Company securities at 30 September 2013
-
-
-
-
-
-
25
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Details of remuneration (continued)
Table 2: Share based compensation – Options granted and vested during the year
Non-Executive Directors
Andrew Whittle
Year
2014
Number of
options
granted1
Grant
date
Average
fair value
at grant
date1
Average
exercise
price per
option1
Number of
options
vested1
Proportion
of options
vested
%
Expiry
date
-
-
-
-
-
-
-
15 Nov 15
2013
900,000
29 Nov 12
$0.40
$0.45
and
300,000
33%
Wrixon Gasteen
2014
-
-
-
-
15 Nov 17
-
15 Nov 15
-
-
2013
1,000,000
29 Nov 12
$0.40
$0.45
and
333,334
33%
Henry Askin2
2014
-
-
-
-
15 Nov 17
-
15 Nov 15
-
-
2013
1,300,000
29 Nov 12
$0.40
$0.45
and
433,334
33%
William Dunmore
Robert Hubbard 3
Tom Wilson 4
Peter Moore 5
2014
2013
2014
2013
2014
2013
2014
2013
-
-
-
-
-
-
-
-
Executive Directors and Other Key Management
Personnel
Richard Cottee9
2014
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2013
34,584,407
19 Jul 12
$0.25
$0.45
Michael Herrington
2014
1,800,000
28 Nov 13
$0.0825
$0.475
Daniel White
Bruce Elsholz
Leon Devaney6
Michael Bucknill7
Robbert Willink8
2013
900,000
29 Nov 12
$0.40
2014
2013
2014
2013
2014
2013
2014
2013
2014
2013
2014
2013
733,334
-
570,000
-
560,000
-
-
-
-
-
3,663,364
38,684,407
10 Jul 13
-
10 Jul 13
-
10 Jul 13
-
-
-
-
-
$0.058
-
$0.058
-
$0.058
-
-
-
-
-
$0.45
$0.45
-
$0.45
-
$0.45
-
-
-
-
-
15 Nov 17
-
-
-
-
-
-
-
-
-
15 Nov 15
and
15 Nov 17
15 Nov 17
15 Nov 15
and
15 Nov 17
15 Nov 15
-
15 Nov 15
-
15 Nov 15
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
9,683,634
28%
-
-
300,000
33%
733,334
-
570,000
-
560,000
-
-
-
-
-
1,863,334
11,050,302
100%
-
100%
-
100%
-
-
-
-
-
51%
29%
Total compensation
options
1 After 1 for 5 consolidation of all Company securities issued before 30.9.2013
3 Appointed 6 December 2013
5 Appointed 14 April 2014
7 Appointed 1 July 2013
9 Freestone Energy Partners Pty Ltd (“FEP”) have provided the services of Richard Cottee on the basis of a secondment. As such compensation is made to FEP in
line with Richard Cottee’s service agreement shown on page 31. Richard Cottee has a 50% beneficial equity interest in FEP.
2 Retired 30 November 2013
4 Appointed 31 March 2014
6 Appointed 6 November 2012
8 Appointed 1 July 2013
26
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Details of remuneration (continued)
Table 3: Options granted as part of remuneration
2014
Non-Executive Directors
Andrew Whittle
William Dunmore
Wrixon Gasteen
Robert Hubbard1
Tom Wilson2
Peter Moore3
Executive Directors and Other Key
Management Personnel
Richard Cottee
Michael Herrington
Bruce Elsholz
Daniel White
Leon Devaney
Michael Bucknill4
Robbert Willink5
2013
Non-Executive Directors
Andrew Whittle
William Dunmore
Wrixon Gasteen
Henry Askin6
Executive Directors and Other Key
Management Personnel
Richard Cottee
Michael Herrington
Bruce Elsholz
Daniel White
Leon Devaney
1 Appointed 6 December 2013
3 Appointed 14 April 2014
5 Appointed 1 July 2013
Value of options
granted during the
year
($)
Value of options
lapsed during the
year
($)
Remuneration
consisting of options
for the year
(%)
-
-
-
-
-
-
-
148,500
33,060
42,534
32,480
-
-
-
(55,928)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
18%
9%
8%
9%
-
-
Value of options
granted during the
year
($)
Value of options
lapsed during the
year
($)
Remuneration
consisting of options
for the year
(%)
361,500
-
401,666
522,166
8,653,019
361,500
-
-
-
-
-
-
-
-
-
-
-
-
2 Appointed 31 March 2014
4 Appointed 1 July 2013
6 Retired 20 November 2012
41%
-
49%
68%
75%
15%
-
-
-
No other options were exercised during either year, and no shares were issued on exercise of compensation options.
27
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Details of remuneration (continued)
Table 4: Shareholdings of key management personnel
(All shareholding numbers adjusted for the 1 for 5 consolidation of the Company’s securities at 30 September 2013)
Held at
beginning
of year
Held at
date of
appointment
On market
purchases
Received on
exercise of
options
Net change
other
Held at
date of
departure
Held at
end of
year
N/A
N/A
N/A
N/A
N/A
N/A
183,743
155,334
104,000
-
133,680
80,000
Non-Executive Directors
Andrew Whittle
2014
2013
William Dunmore
2014
2013
Wrixon Gasteen
2014
2013
Henry Askin 1
2014
2013
Robert Hubbard 2
2014
2013
Tom Wilson 3
2014
2013
Peter Moore 4
-
2014
2013
N/A
Executive Directors and Other Key Management
Personnel
N/A
774,546
64,100
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
-
N/A
208,683
-
200,000
-
288,000
288,000
-
-
110,000
-
-
-
-
-
Richard Cottee
2014
2013
Michael Herrington
2014
2013
Daniel White
2014
2013
Bruce Elsholz
2014
2013
Leon Devaney
2014
2013
Michael Bucknill
2014
2013
Robbert Willink
2014
2013
1 Retired 30 November 2012
2 Appointed 6 December 2013
3 Appointed 31 March 2014
4 Appointed 14 April 2014
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
31,000
N/A
-
N/A
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
28,104
(7,000)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
N/A
N/A
N/A
N/A
N/A
N/A
133,680
133,680
183,743
183,743
97,000
104,000
N/A
774,546
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
64,100
N/A
-
N/A
-
N/A
208,683
208,683
200,000
200,000
288,000
288,000
-
-
110,000
110,000
31,000
N/A
-
N/A
-
53,680
-
-
-
104,000
-
-
-
-
-
-
-
-
-
208,683
-
200,000
-
-
-
-
-
110,000
-
-
-
-
28
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Details of remuneration (continued)
Table 5: Option holdings of key management personnel
(All options issued prior to the Company’s securities consolidation on 30 Sept 2013 have been adjusted to reflect that 1 for 5 consolidation.)
Held at
beginning
of year
Options
exercised
Granted as
remuneration
Net
change
other
Held at
date of
departure
Held at
end of
year
Non-Executive Directors
Andrew Whittle
2014
2013
William Dunmore
2014
2013
Wrixon Gasteen
2014
2013
Henry Askin1
2014
2013
Robert Hubbard
2014
2013
Tom Wilson
2014
2013
Peter Moore
2014
2013
900,000
-
280,000
280,000
1,000,000
-
N/A
668,000
N/A
N/A
N/A
N/A
N/A
N/A
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
900,000
-
-
-
-
(280,000)
-
-
1,000,000
N/A
1,300,000
-
N/A
-
N/A
-
N/A
-
-
N/A
-
-
-
-
-
-
-
N/A
N/A
N/A
N/A
N/A
N/A
900,0002
900,000
-
280,000
1,000,0003
1,000,000
N/A
1,968,000
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
-
N/A
-
N/A
-
N/A
Held at
beginning
of year
Options
exercised
Granted as
remuneration
Net change
other
Held at
date of
departure
Held at
end of
year
Executive Directors and Other
Key Management Personnel
-
-
-
-
-
-
-
-
-
-
2,700,0002
900,000
34,584,4077
34,584,407
N/A
N/A
N/A
N/A
733,334
-
929,200
929,200
1,800,000
900,000
-
34,584,407
34,584,407
-
900,000
-
Richard Cottee
2014
2013
Michael Herrington
2014
2013
Daniel White
2014
2013
Bruce Elsholz
2014
2013
Leon Devaney
2014
2013
Michael Bucknill5
2014
2013
Robert Willink6
2014
2013
1 retired 30 November 2012
3 333,334 have vested at 30 June 2014
5 100,000 options issued 17 July 2014
7 34,584,407 unlisted options exercisable at $0.45 on or before 15 November 2015 and 15 November 2017 were issued to FEP on 8 August 2012, a
company in which Richard Cottee has a 50% beneficial equity interest. At 30 June 2014; 9,683,634 have vested.
-
N/A
2 300,000 have vested at 30 June 2014
4 all options had vested and were exercisable at 30 June 2014
6 120,000 options issued 17 July 2014
(19,200)
-
570,000
-
600,000
600,000
560,000
-
-
-
-
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
1,170,0004
600,000
1,643,3344
929,200
560,0004
-
-
N/A
-
N/A
-
-
-
-
-
-
-
-
29
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
Details of remuneration (continued)
The vesting profile for options (Note 1) held at the end of the year was as follows:
Executive
2014
2013
Holding at
end of year
Vested during
the year
Exercisable at
end of
year
Holding at
end of year
Vested during
the year
Exercisable at
end of year
Executive Directors and Other Key
Management Personnel
Richard Cottee
34,584,407
-
9,683,407
34,584,407
9,683,634
9,683,634
Michael Herrington
Daniel White
Bruce Elsholz
Leon Devaney
Michael Bucknill
Robbert Willink
2,700,000
1,643,334
1,170,000
560,000
-
-
-
733,334
570,000
560,000
-
-
300,000
1,643,334
1,170,000
560,000
-
-
900,000
929,200
600,000
-
N/A
N/A
300,000
-
-
-
N/A
N/A
300,000
929,200
600,000
-
N/A
N/A
Note 1: All options issued prior to the Company’s securities consolidation on 30 September 2013 have been adjusted to reflect that 1 for 5
consolidation.
For each grant of options included in the tables 1 to 5 above, the percentage of the grant that was vested in the
financial year and the percentage that was forfeited because the person did not meet the performance or service
criteria are set out below. The options vest over a range of time frames provided the vesting conditions are met.
No options will vest if the conditions are not satisfied (refer page 23), hence the minimum value of the option yet
to vest is nil. The maximum value of the options yet to vest has been determined as the amount of the grant
date fair value of the options that is yet to be expensed.
Share based compensation benefits (options)
Name
Andrew Whittle
William Dunmore
Wrixon Gasteen
Henry Askin1
Richard Cottee
Michael Herrington
Daniel White
Bruce Elsholz
Leon Devaney
Year
Granted
2013
2009
2008
2013
2013
2008
2009
2013
2014
2013
2014
2012
2010
2014
2012
2010
2014
Vested
%
33
100
100
33
33
100
100
28
0
33
100
100
100
100
100
100
100
Forfeited
%
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Financial years
in which options
may vest
2014 to 2017
-
-
2014 to 2017
2014 to 2017
-
-
2014 to 2017
2015 to 2017
2014 to 2017
Maximum value
of grant yet to
vest
$
292,276
-
-
324,751
422,176
-
-
6,868,838
148,500
292,276
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Directors Messrs Hubbard, Wilson and Moore will not be granted options. No further options will be granted to
Directors Messrs Whittle, Dunmore, Gasteen, Cottee, Herrington or Askin (now retired).
KMPs Messrs Bucknill and Willink were granted options after 30 June 2014.
30
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
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
• Mr Cottee is seconded under an Intercompany Services Agreement with Freestone Energy Partners Pty
•
•
•
Ltd (“FEP”) for a three year term.
The term of the agreement expires 29 June 2015;
The Company pays FEP $518,783 per annum for Mr Cottee’s services.
Termination is not applicable for the initial term of the secondment, except in certain exceptional
circumstances (such as breach or gross misconduct) where a shorter time applies.
Mike Herrington, Executive Director and Chief Operating Officer
•
• Mr Herrington’s base salary is presently $465,000 per annum. In addition, superannuation at 9.5% is
The term of the agreement expires 28 January 2016.
•
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.
Bruce Elsholz, Chief Financial Officer
•
• Mr Elsholz’s base salary is presently $315,000 per annum. In addition, superannuation at 9.5% is
The term of the agreement expires 30 August 2017.
applicable. The salary is reviewed annually.
• Mr Elsholz resigned his position of Company Secretary effective 25 August 2014 and has given notice of
his retirement from Central effective 30 November 2014.
Daniel White, Group General Counsel and Company Secretary
•
• Mr White’s base salary is presently $385,000 per annum. In addition, superannuation at 9.5% is applicable.
The term of the agreement expires 29 November 2017.
•
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.
Leon Devaney, Chief Commercial Officer
•
• Mr Devaney’s base salary is presently $325,000 per annum. In addition, superannuation at 9.5% is
The term of the agreement expires 15 November 2015.
•
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.
Michael Bucknill, General Manager, Exploration
•
• Mr Bucknill’s base salary is presently $320,000 per annum. In addition, superannuation at 9.5% is
The term of the agreement expires 30 June 2017.
•
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.
Robbert Willink, Exploration Advisor
•
• Mr Willink’s base salary is presently $340,000 per annum. In addition, superannuation at 9.5% is
The term of the agreement expires 30 June 2017.
•
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.
31
CENTRAL PETROLEUM LIMITED
ABN 72 083 254 308
DIRECTORS’ REPORT
30 JUNE 2014
•
Service agreements (continued)
Directors
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. Mr Whittle,
Chairman of the Board, receives a non-executive directors’ fee of $95,000 per annum. Messrs Cottee,
Herrington, Gasteen, Dunmore, Hubbard, Wilson and Moore receive directors’ fees of $65,000 per annum.
Mr Gasteen receives an additional fee of $10,000 per annum for acting as Chairman of the Audit Committee. Mr
Hubbard receives an additional fee of $10,000 per annum for acting as Chairman of the Remuneration
Committee and $5,000 per annum for his role as a member of the Audit Committee. Mr Moore receives an
additional fee of $10,000 per annum for acting as Chairman of the Nominations Committee and $5,000 per
annum for his role as a member of the Remuneration Committee. Mr Whittle is a member of each of the three
Board Committees for which he receives an additional fee of $5,000 per annum per committee. Mr Cottee
receives an additional fee of $5,000 per annum for his role as a member of the Nominations Committee.
The directors also receive superannuation benefits except for Messrs Gasteen, Dunmore and Wilson, who
reside outside of Australia.
Signed in accordance with a resolution of the Directors:
Richard Cottee – Managing Director, Brisbane 30 September, 2014
32
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
CORPORATE GOVERNANCE STATEMENT
Introduction
The Company and the board are committed to achieving and demonstrating high standards of corporate
governance. The board continues to review the framework and practices to ensure they meet the interests of
shareholders. The Group seeks to follow the best practice recommendations for listed companies to the extent
that it is practicable.
The Company is required to disclose the extent to which it has not adopted the ASX Corporate Governance
Principles and Recommendations. Set out below are the principal corporate governance practices of the
Company along with the reasons for non-adoption of the recommendations (including 2010 Amendments) where
applicable.
Principle 1: Lay solid foundations for management and oversight
Role of the board of Directors
The board of directors guides and monitors the business and affairs of the Company on behalf of its
shareholders, by whom the directors are elected and to whom they are accountable.
The board’s primary role is the protection and enhancement of long-term shareholder value. The board is
responsible for the overall corporate governance of the Company, including engaging with management in the
development of strategic and business plans, preparation of annual budgets and establishment of goals for
management and monitoring the achievement of those goals on a regular basis. Management will report to the
board and execute the directives of the board.
The board is also responsible for:
•
•
•
•
•
•
reviewing the performance of the managing director and senior management;
planning the development, retention and succession of the management team;
reviewing and ratifying systems of risk management and internal compliance, including approving and
monitoring the policies and procedures relating to occupational health and safety and the environment;
approving and monitoring financial and other reporting, including the progress of major capital
expenditure and capital management;
approving and monitoring acquisitions and divestitures; and
preparing, implementing and monitoring policies to ensure that all major developments affecting the
financial position and state of affairs of the Company and any subsidiaries are announced to the ASX in
strict accordance with the Listing Rules.
The board has also established a framework for the management of the Company, including a system of internal
control and business risk management and the establishment of appropriate ethical standards. The board
conducts annual reviews of its processes to ensure that it is able to carry out its functions effectively and in an
efficient manner.
The board from time to time carries out the process of considering and determining relevant KPI’s and other
measures to evaluate the performance of its senior executives.
Principle 1.1 recommendations not currently adopted:
Recommendation
Explanation/ Reference
Rec 1.1 Companies should establish
functions
reserved to the board and those delegated to
senior executives and disclose the functions.
the
formalised
The Company has not
the
functions reserved to the board and those
delegated to management. However, the
responsibilities of the board are set out
above.
34
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
CORPORATE GOVERNANCE STATEMENT
Principle 2: Structure the board to add value
Structure and composition of the board
The board consists of five directors – two executive directors and three non–executive directors. Details of their
skills, experience and expertise and the period of office held by each director have been included in the
directors’ report. The number of board meetings and the attendance of the directors are set out in the directors’
report.
The Chairman, Mr Whittle, is a non-executive director. The roles of chairman and the executive director are not
exercised by the same individual as there is a clear division of responsibility between them.
Independence of non-executive directors and the chairman of the board
The board monitors the independence of each board member on a regular ongoing basis.
The board has assessed the independence of the non-executive directors and the Chairman.
Although Messrs Dunmore, Whittle and Gasteen hold 918,711, 668,397 and 520,000 fully paid ordinary shares
respectively, the board considers these holdings to be immaterial, being significantly below the holdings
threshold to be considered as substantial shareholders as defined by the Corporations Act.
The non-executive directors have no business or other relationship which is likely to compromise their
independence. Individual directors are required to keep the board advised of any interests that could potentially
create conflict with those of the Company.
Nominations Committee
The nominations committee consists of the following directors:
Peter Moore (Chair)
Richard Cottee
Andrew Whittle
Details of these directors’ qualifications are set out in the directors’ report.
The role of the Nominations Committee is to review Board composition, performance and Board succession
planning.
Conflict of Interest
Directors and senior management are required to advise the Chairman of any existing or potential conflict of
interest. When necessary, the Chairman will refer the matter to the board for determination.
Term of office
Under the constitution of the Company, the directors, other than the Managing Director, are obliged to present
one third of their company for retirement and potential re-election at each annual general meeting of the
Company.
Independent professional advice
In the proper performance of their duties, each director has the right to seek a reasonable level of independent
professional advice on matters concerning the Company at the Company’s expense, after obtaining the
Chairman’s approval, which will not be unreasonably withheld. Each director has the right of access to all
relevant Company information and to the Company’s executives.
Principle 2.5 recommendation is currently not adopted:
Recommendation
Explanation/ Reference
Rec 2.5 Companies should disclose the process for
evaluating the performance of the board, its
committees and individual directors
Given the size and nature of the Company a formal
process for performance evaluation has not yet been
developed.
35
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
CORPORATE GOVERNANCE STATEMENT
Principle 3: Promote ethical and responsible decision making
Ethical standards and code of conduct
The directors acknowledge the need for, and continued maintenance of, the highest standards of ethical conduct
by all directors and employees of the Company. All directors, executives and employees are required to abide by
laws and regulations, to respect confidentiality and the proper handling of information and act with their highest
standards of honesty, integrity, objectivity and ethics in all dealings with each other, the Company, customers,
suppliers and the community.
The board has developed a Code of Conduct reflecting its high standards and expectations. The Code of
Conduct will be regularly reviewed and updated as necessary to ensure it reflects the highest standards of
behaviour and professionalism.
The Code of Conduct is available on the Central Petroleum Limited website.
Share trading
The Company has adopted a Share Trading Policy for the directors and employees, which is appropriate for a
Company whose shares are admitted to trading on the ASX, and the Company will take all reasonable steps to
ensure compliance by its directors and any relevant employees. The Share Trading Policy is summarised as
follows:
• Consistent with the legal prohibitions on insider trading contained in the Corporations Act, all
employees, officers and directors are prohibited from trading in the Company’s securities while in
possession of unpublished price sensitive information.
• Unpublished price sensitive information is information, which a reasonable person would expect to have
a material affect on the price or value of the Company’s securities. Examples may include:
o
o
o
o
the financial results of the Company and any of its subsidiaries;
projections of future earnings or losses;
changes in senior management; and
results of drilling and or production testing.
It should be noted that either positive or negative information may be material.
An employee, officer or director, whilst in possession of unpublished price sensitive information, is subject to
three restrictions:
•
•
•
they must not deal in securities affected by information;
they must not cause or procure anyone else to deal in those securities; and
they must not communicate the information to any person if they know or ought to know that the other
person will use the information, directly in directly, for dealings in securities.
Employees, officers and directors are required to advise the Company Secretary of their intentions prior to
undertaking any transaction in the Company’s securities. If an employee, officer or director is considered to
possess unpublished price sensitive information, they will be precluded from making a security transaction until
one trading day after the time of public release of that information.
Related party matters
Directors and senior management are required to advise the Chairman of any related party contract or potential
contract. The Chairman will inform the board and the reporting party will be required to remove himself/herself
from all discussions and decisions involving the matter. Prior board approval will be required for all proposed
contracts.
Diversity
The Company values diversity and recognises the benefits it can bring to the organisation’s ability to achieve its
goals. The Company has formulated a diversity policy, which can be viewed on its website.
At the end of the current reporting period there were 7 women in the whole organisation representing 27% of
total employees. There were no women in senior executive or board positions.
36
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
CORPORATE GOVERNANCE STATEMENT
Principle 4: Safeguard integrity in financial reporting
Reporting and assurance
When considering the financial reports, the board receives a written statement declaration in accordance with
section 295A of the Corporations Act, signed by the Managing Director and Chief Financial Officer that the
Company’s financial reports give a true and fair view, in all material respects, of the Company’s financial position
and its performance and comply in all material respects with relevant accounting standards. This statement also
confirms that the Company’s financial reports are founded on a sound system of risk management and internal
control and that the system is operating effectively in relation to financial reporting risks.
Similarly, in a separate written statement the Managing Director and Chief Financial Officer also confirm to the
board that the Company’s risk management and internal control systems are operating effectively in relation to
material business risks for the period, and that nothing has occurred since period-end that would materially
change the position.
Financial reporting
Monthly results are circulated to the board of directors and Chief Financial Officer for review. Rolling cash flow
forecasts are prepared on a regular basis. Exploration expenditure is measured against approved programme
budgets.
Audit Committee
The board has established an audit committee which consists of the following non-executive directors:
Wrixon Gasteen (Chair)
Andrew Whittle
Robert Hubbard
Details of these directors’ qualifications are set out in the directors’ report.
The audit committee operates in accordance with a charter which is available on the Company’s website.
External Auditors
The Company and audit committee policy is to appoint external auditors who clearly demonstrate quality and
independence. The performance of the external auditor is reviewed regularly. PwC was appointed auditor for
the first time for the financial year ended 30 June 2011. It is PwC’s policy to rotate audit engagement partners
on listed companies at least every five years.
An analysis of fees paid to the external auditors, including a break-down of fees for non-audit services, is
provided in the directors’ report and in note 5 to the financial statements. It is the policy of the external auditors
to provide an annual declaration of their independence to the audit committee.
The external auditor will attend the annual general meeting and be available to answer shareholder questions
about the conduct of the audit and the preparation and content of the audit report.
Principle 5: Make timely and balanced disclosure
Continuous disclosure
The directors are committed to keeping the market fully informed of material developments to ensure
compliance with the listing rules and the Corporations Act. At each board meeting, specific consideration is
given as to whether any matters should be disclosed under the Company’s continuous disclosure policy.
The practice of senior management is to review and authorise any Company announcement to ensure that the
information is factual, timely, clearly expressed and contains all material information so that investors can make
appropriate assessments of the information for investment decisions.
37
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
CORPORATE GOVERNANCE STATEMENT
Principle 5.1 recommendation is currently not adopted:
Recommendation
Rec 5.1 Companies
should
establish written
policies designed to ensure compliance
with ASX
disclosure
Listing Rule
requirements and to ensure accountability
at a senior level for that compliance and
disclose those policies or a summary of
those policies.
Explanation/ Reference
The Company has established a practice of evaluating
continuous disclosure issues as a part of each formal
board meeting. The board is acutely aware of the
continuous disclosure regime and believes there are
strong informal systems in place to ensure compliance.
Disclosure of the Company’s approach to continuous
disclosure is set out above.
Principle 6: Respect the rights of shareholders
Shareholder relations
The directors aim to ensure that the shareholders, on behalf of whom they act, are informed of all information
necessary to assess the performance of the Company.
Information on all major developments affecting the Company is available to shareholders through:
•
•
•
the Company’s annual report;
quarterly and half yearly reports;
the annual general meeting of the Company and other meetings called to obtain approval for board
actions as appropriate. All shareholders who are unable to attend these meetings will be encouraged to
communicate issues or ask questions by writing or emailing to the Company; and
• mandatory ASX announcements on the Company website.
The Company will take advantage of technology, such as the Company website, to provide greater opportunities
for effective communication with shareholders and to encourage participation at meetings.
Information disclosed to the Australian Securities Exchange (“ASX”) is available to shareholders via the ASX
website. In addition various reports and announcements are made available on the Company’s website where
there is also an option for shareholders to register their email address for updates made by the Company from
time to time. All shareholders are entitled to receive a copy of the Company’s annual and half-yearly reports and
these reports are also made available on the Company’s website.
Principle 7: Recognise and manage risk
The board is responsible for satisfying itself annually, or more frequently as required, that management has
developed and implemented a sound system of risk management and internal control. Detailed work on this
task is delegated to the audit committee for review by the full board.
The audit committee is responsible for ensuring there are adequate policies in relation to risk management,
compliance and internal control systems. In providing this oversight they review and obtain reasonable
assurance that the financial risk management, internal control and information systems are operating effectively
to produce accurate, appropriate and timely management and financial information.
Business risk management
The board acknowledges that it is responsible for the overall internal control and risk management framework.
Accordingly, the board has implemented the following control framework:
Special functional reporting:
The board has identified a number of key areas which are subject to regular reporting to the board such as
safety, environmental, insurance and legal matters.
Investment appraisal:
The Company has set clearly defined guidelines for capital expenditure. These include annual budgets, detailed
appraisal and review procedures, levels of authority and due diligence requirements. Capital expenditure and
revenue commitments above a certain size require prior board approval. Procedures exist to ensure that
business transactions are properly authorised and executed.
38
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
CORPORATE GOVERNANCE STATEMENT
The Board receives regular reports about the financial condition and operating results of the Group. The
Managing Director and Chief Financial Officer annually provide a declaration in the form required by section
295A of the Corporations Act.
Principle 7.1 and 7.2 recommendations not complied with:
Recommendation
Rec 7.1 Companies should establish policies
the
oversight and management of material business
risks and disclose a summary of those policies.
for
Rec 7.2 The Board should require management to design
and implement the risk management and internal
control system to manage the Company’s material
business risks and report to it on whether those
risks are being managed effectively. The board
should disclose that management has reported to it
as
the Company’s
the effectiveness of
management of its material business risks.
to
Explanation/ Reference
The Company has not established a formal,
written risk management policy. Disclosure of
the Company’s approach to risk management
is set out above.
The Company has not established a formal,
written risk management and internal control
system.
the Company’s
approach to risk management and internal
control is set out above.
Disclosure of
Principle 8: Remunerate fairly and responsibly
On matters of remuneration, the board has policies that were established to review the remuneration policies
and practices of the Company to ensure that it remunerates fairly and responsibly.
Remuneration Committee
The Remuneration Committee consists of the following directors:
Robert Hubbard (Chair)
Peter Moore
Andrew Whittle
Details of these directors’ qualifications are set out in the directors’ report.
The remuneration policy of the board is designed to ensure that the level and composition of remuneration is
competitive, reasonable and appropriate for the results delivered and to attract and maintain talented and
motivated directors and employees. The policy is designed for:
•
•
•
•
decisions in relation to executive and non-executive remuneration policy;
decisions in relation to remuneration packages for executive directors and senior management;
decisions in relation to merit recognition arrangements and termination arrangements; and
ensuring that any equity-based executive remuneration is made in accordance with the thresholds set
in plans approved by shareholders.
Non-executive directors’ remuneration policy
The structure of non-executive directors’ remuneration is distinguished from that of executives. Remuneration for
non-executive directors is fixed. Total remuneration for all directors, as approved by shareholders, is not to
exceed $750,000 per annum. Neither the non-executive directors nor the executives of the Company receive
any retirement benefits, other than superannuation.
Executive directors’ remuneration policy
Executive directors are employed pursuant to employment agreements, except for Richard Cottee whose
services are provided to the Company by a secondment arrangement under an Intercompany Services
Agreement with Freestone Energy Partners Pty Ltd. A summary of the Executive Director’s employment
agreement is set out in the remuneration report.
39
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
AUDIT REPORT
Contents Page
Financial statements
Consolidated statement of comprehensive income ............................................................................41
Consolidated statement of financial position ......................................................................................42
Consolidated statement of changes in equity .....................................................................................43
Consolidated statement of cash flows ................................................................................................44
Notes to the consolidated financial statements ..................................................................................45
Directors’ declaration .....................................................................................................................................88
Independent auditor’s report to the members ................................................................................................89
ASX additional information .............................................................................................................................91
These financial statements are the consolidated financial statements of the Consolidated Entity 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:
56-58 Jephson Street
Toowong
Queensland 4066
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 6 to 21. These
pages are not part of these financial statements.
The financial statements were authorised for issue by the directors on 30 September 2014. 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,
links on our website:
www.centralpetroleum.com.au
information are available via
financial reports and other
the
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
C O N S O L I D AT E D S T AT E M E N T O F C O M P R E H E N S I V E I N C O M E
F O R T H E Y E AR E N D E D 30 J U N E 2014
Operating revenue
Cost of sales
Gross profit
Other income
Share based employment benefits
General and administrative expenses
Business combination transaction fees
Depreciation & amortisation
Employee benefits and associated costs
Exploration expenditure
Finance costs
Loss before income tax
Income tax credit
Loss for the year
Note
2014
$
2013
$
3,718,102
(3,016,494)
701,608
1,530,668
(2,818,231)
(2,517,230)
(1,914,004)
(1,127,155)
(3,120,279)
(4,659,886)
(1,040,975)
-
-
-
9,278,979
(2,168,210)
(5,274,931)
-
(456,880)
(3,666,321)
(6,977,912)
(18,118)
(14,965,484)
(9,283,393)
4,107,498
-
(10,857,986)
(9,283,393)
2
30(c)
33
3
3
4
20
Other comprehensive loss for the year, net of tax
-
-
Total comprehensive loss for the year
(10,857,986)
(9,283,393)
Total comprehensive loss attributable to
members of the parent entity
(10,857,986)
(9,283,393)
Basic and diluted loss per share (cents)
21
(3.42)
(3.30) 1
1 On 27 September 2013 the shareholders approved that every 5 ordinary shares held be converted into 1 ordinary share
(subject to rounding). Due to share consolidation, the 30 June 2013 basic and diluted earnings per share have been
restated to reflect the share consolidation impact on the 30 June 2013 contributed equity.
The accompanying notes form part of these financial statements.
41
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
C O N S O L I D AT E D S T AT E M E N T O F F I N AN C I AL P O S I T I O N
AS AT 30 J U N E 2014
ASSETS
Current assets
Cash and cash equivalents
Trade and other receivables
Inventories
Assets held for sale
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
Interest-bearing liabilities
Provisions
Total current liabilities
Non-current liabilities
Interest-bearing liabilities
Provisions
Total non-current liabilities
Total liabilities
Net assets
EQUITY
Contributed equity
Reserves
Accumulated losses
Total equity
Note
2014
$
2013
$
6
7
8
9
10
11
12
13
33
14
15
16
15
17
10,330,474
2,953,300
1,940,983
1,000,000
1,308,307
6,934,816
975,281
-
16,224,757
9,218,404
46,266,152
16,869,693
19,521
2,423,185
3,906,270
1,285,300
16,702,228
29,294
1,854,620
-
69,484,821
19,871,442
85,709,578
29,089,846
10,476,308
255,760
2,236,372
3,332,034
-
952,179
12,968,440
4,284,213
23,761,593
5,910,832
29,672,425
-
159,709
159,709
42,640,865
4,443,922
43,068,713
24,645,924
18
19
20
155,223,040
14,448,696
(126,603,023)
130,258,022
10,132,939
(115,745,037)
43,068,713
24,645,924
The accompanying notes form part of these financial statements.
42
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
C O N S O L I D AT E D S T AT E M E N T O F C H AN G E S I N E Q U I T Y
F O R T H E Y E AR E N D E D 30 J U N E 2014
Contributed
equity
$
Reserves
$
Accumulated
Losses
$
Total
$
Total equity at 1 July 2012
122,700,723
7,964,729
(106,461,644)
24,203,808
Total loss for the year
Other comprehensive loss
Total comprehensive loss for the year
Transactions with owners in their
capacity as owners
Share based payments
Share and option issues
Share issue costs
-
-
-
-
7,560,206
(2,907)
-
-
-
(9,283,393)
(9,283,393)
-
-
(9,283,393)
(9,283,393)
2,168,210
-
-
7,557,299
2,168,210
-
-
-
-
2,168,210
7,560,206
(2,907)
9,725,509
Balance at 30 June 2013
130,258,022
10,132,939
(115,745,037)
24,645,924
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
-
-
-
-
-
25,614,373
(649,355)
-
-
-
(10,857,986)
(10,857,986)
-
-
(10,857,986)
(10,857,986)
2,818,231
1,497,526
-
-
24,965,018
4,315,757
-
-
-
-
-
2,818,231
1,497,526
25,614,373
(649,355)
29,280,775
Balance at 30 June 2014
155,223,040
14,448,696
(126,603,023)
43,068,713
The accompanying notes form part of these financial statements.
43
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AB N 7 2 0 8 3 2 5 4 3 0 8
C O N S O L I D AT E D S T AT E M E N T O F C AS H F L O W S
F O R T H E Y E AR E N D E D 30 J U N E 2014
Note
2014
$
2013
$
Cash flows from operating activities
Receipts from customers
Interest received
Other income
Interest & borrowing costs
Payments to suppliers and employees (inclusive of GST)
2,105,060
406,273
7,931,000
(375,000)
(9,589,572)
-
140,500
2,488,000
(18,117)
(14,762,849)
Net cash inflow / (outflow) from operating activities
26
477,761
(12,152,466)
Cash flows from investing activities
Payments for property, plant and equipment
Payments for exploration assets
Payments to acquire subsidiary
Payment of business combinations transaction fees
Proceeds from sale of investments
Redemption / (Acquisition) of security deposits and
bonds
33
33
(3,344,272)
-
(20,595,871)
(1,914,004)
-
(566,466)
(642,300)
(500,000)
-
-
1,800,000
56,460
Net cash inflow/(outflow) from investing activities
(26,420,613)
714,160
Cash flows from financing activities
Proceeds from the issue of shares and options
Proceeds from borrowings
Net cash inflow from financing activities
Net (decrease)/increase in cash and cash
equivalents
Cash and cash equivalents at the beginning of the
financial year
Cash and cash equivalents at the end of the financial
year
Non-cash financing and investing activities
6
27
9,965,018
25,000,000
34,965,018
641,381
-
641,381
9,022,167
(10,796,925)
1,308,307
12,105,232
10,330,474
1,308,307
The accompanying notes form part of these financial statements.
44
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AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
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 “Consolidated Entity”).
(a)
Basis of Preparation
These general purpose financial statements have been prepared in accordance with Australian Accounting
Standards and Interpretations of 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 consolidated financial statements of the Group have been prepared on a going concern basis, which
contemplates continuity of business activities and realisation of assets and the settlement of liabilities in the
ordinary course of business. For the year ended 30 June 2014 the Group incurred a loss before tax of
$14,965,484 (2013: $9,283,393) and a cash inflow from operating activities of $477,761 (2013: outflow of
$12,152,466). These results are consistent with the initial exploration, appraisal, development and production
phase of the business. Consequently the Group may need to raise further equity capital in the future.
As at 30 June 2014 the Group had cash assets including joint arrangement balances amounting to $10,330,474.
Since year end, the company has entered into binding agreements to raise an additional $6,000,000 from a
share placement, funds to be received no later than 1 October 2014.
The Group continually monitors its cash flow requirements to ensure that it has sufficient funds to meet its
contractual commitments and adjusts its spending, particularly with respect to discretionary exploration activity
and corporate overhead accordingly. The Directors have also, during the year, undertaken a strategic review of
the Group’s operations and portfolio. The result of the strategic review has been a significant reduction in the
Group’s overheads and a number of initiatives to streamline the Group’s business.
Furthermore Central Petroleum executed an Equity Line of Credit (ELOC) facility with Long State Investment
Limited (LSI) in June 2013. The term of the ELOC is 2 years (June 2015), with an option for Central to extend it
for a further 6 months. Under the facility, Central may place ordinary shares with LSI at the prevailing 5-day
VWAP subject to a maximum of $250,000 for each 5 ASX trading days and a total aggregate funding under the
ELOC of $10 million. Further terms of the ELOC are set out in note 18(g).
The Directors believe that the Company will be successful in sourcing funds when required and will meet its
debts and commitments as they fall due and, accordingly, have prepared the financial statements on a going
concern basis.
The directors, therefore, are of the opinion that no asset is likely to be realised for an amount less than the
amount it is recorded in the financial report at 30 June 2014. Accordingly no adjustments have been made to
the financial report relating to the recoverability and classification of the asset carrying amounts and
classification of liabilities that might be necessary should the Group not continue as a going concern.
(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 2013 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:
45
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F O R T H E Y E AR E N D E D 30 J U N E 2014
1.
Summary of significant accounting policies (continued)
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.
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,
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.
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)
(i)
Principles of consolidation
Subsidiaries
The consolidated financial statements incorporate the assets and liabilities of all subsidiaries of Central
Petroleum Limited (‘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. The acquisition method is used to
account for business combinations by the Group.
Intercompany transactions, balances and unrealised gains on transactions between Group companies are
eliminated. Unrealised losses are also eliminated unless the transaction provides evidence of the impairment of
the asset transferred. Accounting policies of subsidiaries have been changed where necessary to ensure
consistency with the policies adopted by the Group.
Non controlling interests (if applicable) in the results and equity of subsidiaries are shown separately in the
statement of comprehensive income, statement of changes in equity and statement of financial position
respectively.
46
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F O R T H E Y E AR E N D E D 30 J U N E 2014
1.
(b)
Summary of significant accounting policies (continued)
Principles of consolidation (continued)
Joint Arrangements
(ii)
Under AASB 11 Joint Arrangements investments in joint arrangements are classified as either joint operations or
joint ventures. The classification depends on the contractual rights and obligations of each investor, rather than
the legal structure of the joint arrangement.
Joint operations
The Group recognises its direct right to the assets, liabilities, revenues and expenses of joint operations and its
share of any jointly held or incurred assets, liabilities, revenues and expenses. These have been incorporated in
the financial statements under the appropriate headings. Details of the joint operation are set out in note 32.
(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.
Transactions and balances
(ii)
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 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:
(i)
Sale of oil and gas
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.
(ii)
Interest Income
Interest revenue is recognised on a time proportionate basis that takes into account the effective yield on the
financial assets.
(iii)
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.
47
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F O R T H E Y E AR E N D E D 30 J U N E 2014
1.
(f)
Summary of significant accounting policies (continued)
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 Company 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.
(g)
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 29). 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.
(h)
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.
48
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F O R T H E Y E AR E N D E D 30 J U N E 2014
1.
(i)
Summary of significant accounting policies (continued)
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 three 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.
(j)
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.
(k)
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 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.
(l)
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.
49
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F O R T H E Y E AR E N D E D 30 J U N E 2014
1.
(m)
Summary of significant accounting policies (continued)
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, and all development drilling and other subsurface expenditure. 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.
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
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 in the respective asset or group of assets.
(n)
Property, plant and equipment – other than development & 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 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
Expected useful life
40 years
Leasehold Improvements
2 – 6 years
Plant and Equipment
Motor Vehicles
2 – 10 years
5 – 10 years
50
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F O R T H E Y E AR E N D E D 30 J U N E 2014
1.
(o)
Summary of significant accounting policies (continued)
Exploration expenditure
Exploration and evaluation costs are expensed as incurred. Acquisition costs of rights to explore are
accumulated in respect of each separate area of interest. Acquisition costs are carried forward where right of
tenure of the area of interest is current and 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. 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. Amortisation is not charged on costs carried forward in
respect of areas of interest in the development phase until production commences.
(p)
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.
(q)
(i)
Provisions
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
asset (refer to Note 1(m)).
Costs incurred that relate to an existing condition caused by past operations and do not have a future economic
benefit are expensed.
(ii)
Other
Provisions for legal claims and make good obligations are recognised when the Group has a present legal or
constructive obligation as a result of past events, it is probable that an outflow of resources will be required to
settle the obligation and the amount has been reliably estimated. Provisions are not recognised for future
operating losses.
Where there are a number of similar obligations, the likelihood that an outflow will be required in settlement is
determined by considering the class of obligations as a whole. A provision is recognised even if the likelihood of
an outflow with respect to any one item included in the same class of obligations may be small.
Provisions are measured at the present value of management’s best estimate of the expenditure required to
settle the present obligation at the end of the reporting period. The discount rate used to determine the present
value is a pre-tax rate that reflects current market assessments of the time value of money and the risks specific
to the liability. The increase in the provision due to the passage of time is recognised as interest expense.
51
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F O R T H E Y E AR E N D E D 30 J U N E 2014
1.
r)
Summary of significant accounting policies (continued)
Employee benefits
(i)
Short-term obligations
Liabilities for wages and salaries, including non-monetary benefits, annual leave and long service leave
expected to be settled within 12 months after the end of the period in which the employees render the related
service are recognised in respect of employees' services up to the end of the reporting period and are measured
at the amounts expected to be paid when the liabilities are settled. The liability for annual leave and long service
leave is recognised in the provision for employee benefits. All other short-term employee benefit obligations are
presented as payables.
(ii)
Other long-term employee benefit obligations
The liability for long service leave and annual 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 on national government bonds 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 (including directors) by Central Petroleum
Limited.
The fair value of options 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 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.
(s)
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.
(t)
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.
52
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N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
1.
(u)
(i)
Summary of significant accounting policies (continued)
Earnings per share
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.
(v)
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.
(w)
Parent entity financial information
The financial information for the parent entity, Central Petroleum Limited, disclosed in note 23, has been
prepared on the same basis as the consolidated financial statements except as set out below.
(i)
Investments in subsidiaries, associates and joint venture entities
Investments in subsidiaries, associates and joint venture entities are accounted for at cost in the financial
statements of Central Petroleum Limited.
(ii)
Tax consolidation legislation
Central Petroleum Limited and its wholly-owned Australian controlled entities have implemented the tax
consolidation legislation. The head entity, Central Petroleum Limited, and the controlled entities in the 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 stand alone 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.
(x)
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.
53
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
1.
(x)
Summary of significant accounting policies (continued)
Business combinations (continued)
If the business combination is achieved in stages, the acquisition date fair value of the acquirers 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.
(y)
Standards, amendments and interpretations
(i) New and amended standards adopted by the group
The group has applied the following standards and amendments for first time for their annual reporting period
commencing 1 July 2013:
• AASB 10 Consolidated Financial Statements, AASB 11 Joint Arrangements, AASB 12 Disclosure
of Interests in Other Entities, AASB 128 Investments in Associates and Joint Ventures, AASB 127Separate
Financial Statements and AASB 2011-7 Amendments to Australian Accounting Standards arising from the
Consolidation and Joint Arrangements Standards.
• AASB 2012-10 Amendments to Australian Accounting Standards – Transition Guidance and other
Amendments which provides an exemption from the requirement to disclose the impact of the
change in accounting policy on the current period.
• AASB 13 Fair Value Measurement and AASB 2011-8 Amendments to Australian Accounting
Standards arising from AASB 13
• AASB 119 Employee Benefits (September 2011) and AASB 2011-10 Amendments to Australian
Accounting Standards arising from AASB 119 (September 2011)
• AASB 2012-5 Amendments to Australian Accounting Standards arising from Annual Improvements
2009-2011 Cycle.
No changes in accounting policies or adjustments to the amounts recognised in the financial statements resulted
from the adoptions of these standards. The standards only affected the disclosures in the notes to the financial
statements.
policies
(iI) New standards and interpretations not yet adopted
Certain new accounting standards and interpretations have been published that are not mandatory for
30 June 2014 reporting periods. The group have concluded these standards and interpretations are not
expected to have a material impact on the entity in the current or future reporting periods and on foreseeable
future transactions.
54
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AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
2.
Other income
Interest
Research and development refunds
Century legal claim settlement
Gain on sale of investment
Other
Total other income
3.
Expenses
Loss before income tax includes the following specific
expenses:
Depreciation
Buildings
Producing assets
Restoration assets
Plant and equipment
Leasehold improvements
Total depreciation
Amortisation
Software
2014
$
2013
$
307,274
234,170
1,196,296
5,799,252
-
-
1,500,260
1,744,796
27,098
501
1,530,668
9,278,979
7,094
513,435
69,146
502,611
20,824
844
-
-
432,695
850
1,113,110
434,389
14,045
22,491
Write off of property, plant and equipment
-
503,703
Rental expense relating to operating leases –
Minimum lease payments
697,419
1,127,274
Interest paid to suppliers and joint arrangement partners
-
18,118
Finance costs
Interest charge on Macquarie debt facility
Borrowing costs on Macquarie debt facility
Amortisation of deferred finance costs
Accretion charge
55
528,067
375,000
81,956
55,952
1,040,975
-
-
-
6,000
6,000
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
4.
Income tax
This note provides an analysis of the group’s income tax credit, 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.
2014
$
2013
$
-
4,107,498
4,107,498
-
-
-
(14,965,484)
(9,283,393)
4,489,645
2,785,017
-
(439,309)
(253)
(2,553)
(845,469)
(650,463)
344,365
-
-
-
-
-
(12,293)
55,493
5,709
(497,280)
3,549,232
1,683,377
-
-
125,514
(1,808,891)
558,267
4,107,498
-
-
(a) Income tax expense
Current tax
Deferred tax
(b) Numerical reconciliation of income tax expense and
prima facie tax benefit
Loss before income tax expense
Prima facie tax benefit at 30% (2013: 30%)
Tax effect of amounts which are not deductible in calculating
taxable income:
Depreciation on buildings
Non-deductible expenses
Share based payments
Non-assessable income
Movement in items of deferred tax not recognised:
Provisions and accruals
Blackhole expenditure
Accrued income
Capitalised exploration expenditure
Over provision in prior year
Deferred tax assets not recognised
Recognition of previously unrecognised DTA
Income tax credit
56
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
4.
Income tax (continued)
(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 liabilities / (assets) not recognised
Net amounts recognised directly in equity
2014
$
2013
$
(149,335)
(417,463)
149,335
417,463
-
-
(d) Tax losses
Unutilised tax losses for which no deferred tax asset has been
recognised
Potential tax benefit @ 30%
110,171,946
121,551,151
33,051,584
36,465,345
(e) Deferred tax assets and liabilities
Deferred tax assets
Provisions
Blackhole expenditure
Borrowing costs
PRRT
Unutilised losses
Total deferred tax assets before set-offs
2,469,168
627,823
75,422
40,434,838
352,106
842,719
-
-
41,321,238
36,465,345
84,928,489
37,660,170
Set-off of deferred tax liabilities pursuant to set-off provisions
(8,269,654)
(2,949,752)
Net deferred tax assets not recognised
76,658,835
34,710,418
Movements
Opening balance at 1 July
(Charged) / Credited to the income statement
Closing balance at 30 June
2,949,752
3,147,281
5,319,902
(197,529)
8,269,654
2,949,752
Deferred tax assets to be recovered after more than 12 months
8,253,466
2,949,752
Deferred tax assets to be recovered within 12 months
16,188
-
8,269,654
2,949,752
57
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
4.
Income tax (continued)
(e) Deferred tax assets and liabilities
Deferred tax liabilities
Accrued income
Capitalised exploration expenditure
Producing properties
Development well
Other
2014
$
2013
$
2,594
5,709
4,219,124
2,944,043
2,360,870
1,685,650
1,416
-
-
-
Total deferred tax liabilities before set-offs
8,269,654
2,949,752
Set-off of deferred tax liabilities pursuant to set-off provisions
(8,269,654)
(2,949,752)
Net deferred tax liabilities
-
-
Movements
Opening balance at 1 July
Charged / (Credited) to the income statement
DTL arising on Business Combination
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
2,949,752
3,147,281
1,212,404
(197,529)
4,107,498
8,269,654
2,949,752
8,253,466
2,949,752
16,188
-
8,269,654
2,949,752
58
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
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
2014 Audit and review of financial statements
Under provision for 2013 audit and review of financial
statements
Southern Georgina joint arrangement audit
(ii) Taxation services
Tax compliance
(iii) Other services
Magellan transaction due diligence
Remuneration benchmarking
Forensic services
133,506
7,271
3,000
89,850
14,484
-
143,777
104,334
82,266
82,266
83,209
83,209
181,607
10,000
-
191,607
-
12,500
20,240
32,740
Total remuneration of PwC
417,650
220,283
6.
Cash and cash equivalents
Cash at bank and in hand
10,330,474
1,308,307
Made up as follows;
Corporate
Joint arrangements
(a)
(b)
8,740,088
1,248,036
1,590,386
60,271
10,330,474
1,308,307
(a) $2,192,082 of this balance relates to cash drawn from the Macquarie Bank Limited debt facility used to
fund the Dingo Gas field development project. (2013: $nil), and is restricted to use in the project.
(b) $807,914 of this balance relates to the Group share of cash balances held by the Southern Georgina Joint
Arrangement (2013: $51,373).
Risk exposure
The Group’s exposure to interest rate risk is discussed in Note 31. The maximum exposure to credit risk at the
end of the reporting period is the carrying amount of cash and cash equivalents.
59
C E N T R AL P E T R O L E U M L I M I T E D
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N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
7.
Trade and other receivables
Current
Trade receivables
Accrued income
Other receivables
GST receivables
Prepayments
2014
$
2013
$
(a)
868,282
1,311,154
-
286,617
487,247
-
-
888,429
34,513
124,643
Research and development refund from Australian Tax Office
-
5,887,231
2,953,300
6,934,816
(a) Accrued income relates to the revenue recognition of oil and gas volumes delivered to respective customers
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 31.
8.
Inventories
Crude oil & natural gas
Spares parts and consumables
Drilling materials and supplies at cost
9.
Assets held for sale
Land and buildings
97,296
534,691
1,308,996
1,940,983
-
-
975,281
975,281
33
1,000,000
1,000,000
-
-
As part of the Magellan acquisition, an office and yard was acquired in Alice Springs. An independent valuation
was obtained providing a fair value of $1,000,000. The office and yard are to be sold with funds used to retire
debt on the Macquarie finance facility. The Group continues to negotiate the sale.
60
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
10.
Property, plant and equipment
Freehold
Land &
Buildings
$
Producing
Assets
$
Assets in
Development
$
Plant and
equipment
$
Restoration
asset
$
Total
$
Year ended 30 June 2013
Opening net book amount
425,341
Additions
Disposals and write offs
-
-
Depreciation charge
(844)
Closing net book amount
424,497
At 30 June 2013
Cost
430,947
Accumulated depreciation
(6,450)
Net book amount
424,497
Year ended 30 June 2014
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,355,424
442,627
(503,703)
(433,545)
860,803
2,052,625
(1,191,822)
860,803
1,780,765
442,627
(503,703)
(434,389)
1,285,300
2,483,572
(1,198,272)
1,285,300
-
-
-
-
-
-
-
Opening net book amount
424,497
-
-
860,803
-
1,285,300
Additions
Additions – business combs1.
Transfer from exploration
Disposals and write offs
-
-
-
-
2,953,503
2,405,766
1,132,084
107,318
6,598,671
15,859,734
16,013,524
2,953,036
4,201,265
39,027,559
-
-
-
-
-
-
482,535
482,535
(14,803)
-
(14,803)
(523,435)
(69,146)
(1,113,110)
Depreciation charge
(7,094)
(513,435)
Closing net book amount
417,403
18,299,802
18,419,290
4,407,685
4,721,972
46,266,152
At 30 June 2014
Cost
430,947
18,813,237
18,419,290
6,023,358
4,791,118
48,477,950
Accumulated depreciation
(13,544)
(513,435)
-
(1,615,673)
(69,146)
(2,211,798)
Net book amount
417,403
18,299,802
18,419,290
4,407,685
4,721,972
46,266,152
1 Details regarding business combinations are contained in note 33
61
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
2014
$
2013
$
16,869,693
16,702,228
16,702,228
10,488,500
-
-
7,388,793
(1,657,600)
650,000
-
-
482,535
(482,535)
-
16,869,693
16,702,228
33
10
270,373
270,373
(241,079)
(218,588)
29,294
51,785
29,294
4,271
(14,044)
19,521
51,785
-
(22,491)
29,294
274,644
270,373
(255,123)
(241,079)
19,521
29,294
11. Exploration assets
Acquisition costs of rights to explore
Movements for the year:
Balance at the beginning of the year
Expenditure incurred during the year
Expenditure written off during the year
Additions – business combinations
Restoration asset provided for during the year
Restoration asset transferred to producing assets
Balance at the end of the year
12.
Intangible assets
Software
At the beginning of the year
Cost
Accumulated amortisation
Net book value
Movements for the year:
Opening net book amount
Additions
Amortisation
Closing net book amount
At the end of the year
Cost
Accumulated amortisation
Net book value
62
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
13. Other financial assets
Security bonds on exploration permits
Security bonds are provided to State or Territory governments in respect
of certain performance obligations arising from awarded petroleum and
mineral tenements. The bonds are typically provided as cash or as bank
guarantees in favour of the State or Territory government secured by term
deposits with the financial institution providing the bank guarantee.
14.
Trade and other payables
Trade payables
Other payables
Southern Georgina joint arrangement contribution
Accruals
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 31.
15.
Interest bearing liabilities
(a)
Interest bearing liabilities (current) 1
Debt facilities
(a)
Interest bearing liabilities (non-current) 1
Debt facilities
1Details regarding interest bearing liabilities are contained in note 31(d).
2014
$
2013
$
2,423,185
1,854,620
3,893,054
2,572,419
797,713
4,305,514
1,480,027
33,545
322,058
404,012
10,476,308
3,332,034
255,760
255,760
23,761,593
23,761,593
-
-
-
-
63
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
16. Current liabilities - Provisions
Employee entitlements
Onerous contracts
Other
(a) Movements in employee entitlements
Carrying amount at start of year
Provision made during the year
Carrying amount at end of year
2014
$
2013
$
(a)
(b)
626,299
358,324
361,774
1,248,298
51,320
-
2,236,371
409,644
358,324
267,975
626,299
301,027
57,297
358,324
The current provision for employee entitlements includes accrued annual leave and long service leave. For long service leave
it covers all unconditional entitlements where employees have completed the required period of service. The amount is
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 consolidated entity does not expect all employees to take the full amount
of accrued leave or require payment within the next 12 months. The following amounts reflect leave that is not expected to be
taken within the next 12 months.
Leave obligations expected to be settled after 12 months
357,588
128,714
(b) Onerous contracts
A provision for onerous contracts was recognised during the year in respect of operating lease commitments on both167 Eagle
Street, Brisbane and Suite 3, Level 4 South Shore Centre, Perth.
17. Non-current liabilities - Provisions
Restoration and rehabilitation
(a)
4,907,070
542,535
Employee entitlements
Onerous contracts
(a) Movements in restoration and rehabilitation provision
Carrying amount at start of year
Provision made during the year
Provision – business combinations
Accretion charge
Carrying amount at end of year
647,072
356,690
85,747
73,962
5,910,832
702,244
10
33
542,535
107,318
4,201,265
55,952
60,000
482,535
-
-
4,907,070
542,535
Provisions for future removal and restoration costs are recognised where there is a present obligation as a result of
exploration, extended production testing, transportation or storage activities having been undertaken, 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.
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F O R T H E Y E AR E N D E D 30 J U N E 2014
2014
$
2013
$
18. Contributed equity
(a) Share Capital
348,718,957 (2013: 1, 440,078,845) fully paid ordinary shares1
155,223,040
130,258,022
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.
1 On 27 September 2013 shareholders approved every 5 ordinary shares held be converted into 1 ordinary share (subject to
rounding).
(b) Movements in ordinary share capital
Balance at start of year
Placement
to
institutional investors on 26 July
2013 at 10 cents per share
shares
of
Share consolidation
Exercise of listed options at 80
cents per share
Exercise of listed options at 45
cents per share
Placement of shares to Magellan
Petroleum Australia Pty Ltd on 31
March 2014 at 38 cents per share
as part of business combinations
Exercise of listed options at 16
cents per share
Exercise of unlisted options at 9.5
cents per share
Exercise of unlisted options at 11
cents per share
Issue of 50m ordinary shares at
13.8 cents in exchange for the
remaining interest in EP97 from
Rawson Resources Ltd
Capital raising costs
Number of shares
2014
2013
$
2014
$
2013
1,440,078,845
1,383,376,265
130,258,022
122,700,723
106,000,000
(1,236,863,076)
3,904
25,600
39,473,684
-
-
-
-
-
10,600,000
-
3,123
11,250
15,000,000
-
-
-
-
-
-
-
-
-
2,580
4,400,000
2,300,000
50,000,000
-
-
-
-
413
418,000
253,000
6,888,793
-
(649,355)
(2,907)
348,718,957
1,440,078,845
155,223,040
130,258,022
(c) Options granted during the year
The following options over unissued ordinary shares were granted by the Company during the year:
Date of
Issue
Class
Expiry Date
Exercise Price
10 July 2013 Unlisted employee options
28 Nov 2013 Unlisted employee options
10 April 2014 Unlisted employee options
15 Nov 2015
15 Nov 2017
15 Nov 2015
$0.450
$0.475
$0.650
Number of
Options
4,379,334
1,800,000
207,000
65
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F O R T H E Y E AR E N D E D 30 J U N E 2014
18.
Contributed equity (continued)
(d) Options exercised during the year
The following options over unissued ordinary shares were exercised during the year:
Class
Expiry Date
Exercise Price
Listed options (CTPO)
Unlisted employee options
31 Mar 2014
15 Nov 2015
$0.800
$0.450
(e) Options lapsed during the year
The following options over unissued ordinary shares lapsed during the year:
Class
Expiry Date
Exercise Price
Unlisted employee options1
Unlisted employee options
30 Aug 2016
31 Mar 2014
$0.575
Various
1 options forfeited during the year
(f) Unissued shares under option
At year end, options over unissued ordinary shares of the Company are as follows:
Class
Expiry Date
Exercise Price
Number of
Options
3,904
25,000
Number of
Options
200,000
3,173,334
Number of
Options
Unlisted options (CTPO)
Unlisted options (CTPO)
Unlisted shareholder options
Unlisted employee options
Unlisted employee options
Unlisted consulting options
Unlisted employee options
Unlisted director options
Unlisted employee options
Unlisted employee options
Unlisted employee options
Unlisted employee options
Unlisted employee options
Unlisted employee options
Unlisted employee options
Unlisted consulting options
Unlisted director options
Unlisted employee options
31 Mar 2015
30 Sep 2016
31 Mar 2015
31 May 2015
31 Oct 2015
15 Nov 2015
15 Nov 2015
15 Nov 2015
15 Nov 2015
12 May 2016
20 Jul 2016
19 Aug 2016
30 Aug 2016
15 Nov 2016
30 Nov 2016
15 Nov 2017
15 Nov 2017
15 Nov 2017
$0.625
13,000,003
$0.500
$0.625
$0.610
$0.550
$0.450
$0.450
$0.450
$0.650
$0.600
$0.550
$0.575
$0.575
$0.475
$0.475
$0.450
$0.450
$0.475
15,000,000
65,000,000
1,268,000
120,000
9,683,634
4,354,334
1,366,670
207,000
40,000
669,334
400,000
600,000
2,318,668
400,000
24,900,773
2,733,335
1,800,000
None of the options entitle holders to participate in any share issue of the Company or any other entity.
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F O R T H E Y E AR E N D E D 30 J U N E 2014
18. Contributed equity (continued)
(g) 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.
Central Petroleum executed an Equity Line of Credit (ELOC) facility with Long State Investment Limited (LSI) in
June 2013. The term of the ELOC is 2 years (June 2015), with an option for Central to extend it for a further 6
months on payment of $50,000.
Under the facility, Central may place ordinary shares with LSI at the prevailing 5-day VWAP subject to a
maximum of $250,000 for each 5 ASX trading days and a total aggregate funding under the ELOC of $10
million. To activate the ELOC a fee of $200,000 is payable. LSI will receive a 5% commission on any advances
under the ELOC. In addition, LSI will receive up to 5 million unlisted options through 4 separate tranches that
are subject to ELOC utilisation. 1.25 million options will be granted on Activation of the ELOC (first drawdown),
and 1.25 million 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 price of 200% of the 20-day VWAP immediately preceding the
date on which Central is required to grant the Options. The options have an exercise period of 5-years from the
date of issue. To date, Central has not utilised the ELOC and no options have been granted.
2014
$
2013
$
19. Reserves
Share options reserve
14,448,695
10,132,939
Movements:
Balance at start of year
Share based payments costs
Options issued for financing
Balance at end of year
(a)
(b)
10,132,939
2,818,231
1,497,525
7,964,729
2,168,210
-
14,448,695
10,132,939
(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 30 for further
details of share based payments.
(b)
15,000,000 options with an exercise price of $0.50 were issued to Macquarie bank in relation to the $50
million debt facility. These options were valued using a black scholes option pricing model.
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F O R T H E Y E AR E N D E D 30 J U N E 2014
20. Accumulated losses
Movements in accumulated losses were as follows:
Balance at the start of the year
Net loss for the year
Balance at the end of the year
2014
$
2013
$
(115,745,037)
(106,461,644)
(10,857,986)
(9,283,393)
(126,603,023)
(115,745,037)
21.
Loss per share
(a) Basic loss per share (cents)
(3.42)
(3.30)
(b) Diluted loss per share (cents)
(3.42)
(3.30)
(c) Loss used in loss per share calculation
Loss attributable to ordinary equity holders of the Company
(10,857,986)
(9,283,393)
(d) Weighted average number of ordinary shares
Weighted average number of shares used as the denominator
in calculating basic and diluted earnings per share
317,351,393
279,811,5901
Options 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. Refer to Note18 for details of options on issue.
1 On 27 September 2013 shareholders approved every 5 ordinary shares held be converted into 1 ordinary share
(subject to rounding). Due to share consolidation, the 30 June 2013 basic and diluted earnings per share have
been restated to reflect the share consolidation impact on the 30 June 2013 contributed equity.
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F O R T H E Y E AR E N D E D 30 J U N E 2014
22. Segment reporting
The Group has identified its operating segments based on the internal reports that are reviewed and used by the
executive management team (the chief operating decision makers) in assessing performance and in determining
the allocation of resources. The following operating segments are identified by management based on the nature
of the business or venture.
Producing assets
Production and sale of crude oil and pipeline natural gas
Development assets
Development of oil and gas fields
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.
Financing requirements, finance income, finance costs and taxes are managed at a Group level.
The consolidated entity’s operations are wholly in one geographical location being Australia.
Revenue
Cost of sales
Gross profit
Other income
Share based employment benefits
General and administrative expenses
Business combinations transaction fees
Producing
Assets
2014
$
3,718,102
(3,016,494)
701,608
-
-
-
-
Depreciation & amortisation
(513,435)
Employee benefits and associated costs
Exploration expenditure
Finance costs
Loss before income tax
Taxes
Profit / (Loss) for the year
Segment assets
Segment liabilities
Capital expenditure
-
-
-
188,173
-
188,173
Development
Assets
2014
$
Exploration
Assets
2014
$
Unallocated
Items
2014
$
Consolidated
2014
$
3,718,102
(3,016,494)
701,608
-
-
-
1,530,668
1,530,668
(2,818,231)
(2,818,231)
(2,517,230)
(2,517,230)
(1,914,004)
(1,914,004)
(613,720) (1,127,155)
(3,120,279)
(3,120,279)
-
-
-
-
-
-
-
-
-
(4,659,886)
-
(4,659,886)
-
(1,040,975)
(1,040,975)
(4,659,886)
(10,493,771)
(14,965,484)
-
4,107,498
4,107,498
(4,659,886)
(6,386,273)
(10,857,986)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
24,570,779
25,989,302
21,436,107
13,713,391
85,709,578
(4,979,021)
(3,575,974)
(5,250,758)
(28,835,112)
(42,640,865)
Exploration and evaluation assets
PP&E - development and production
assets
PP&E - other
-
-
650,000
22,099,404
19,924,241
-
-
-
-
-
-
650,000
42,023,645
4,085,120
4,085,120
Total capital expenditure
22,099,404
19,924,241
650,000
4,085,120
46,758,765
69
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F O R T H E Y E AR E N D E D 30 J U N E 2014
22.
Segment reporting (continued)
Producing
Assets
2013
$
Development
Assets
2013
$
Exploration
Assets
2013
$
Unallocated
Items
2013
$
Consolidated
2013
$
Revenue
Cost of sales
Gross profit
Other income
Share based employment benefits
General and administrative expenses
Depreciation & amortisation
Employee benefits and associated costs
Exploration expenditure
Finance costs
Loss before income tax
Taxes
Loss for the year
Segment assets
Segment liabilities
Capital expenditure
Exploration and evaluation assets
PP&E - development and production
assets
PP&E - other
Total capital expenditure
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
9,278,979
9,278,979
(2,168,210)
(2,168,210)
(5,274,931)
(5,274,931)
(456,880)
(456,880)
(3,666,321)
(3,666,321)
(6,977,912)
-
(6,977,912)
-
(18,118)
(18,118)
(6,977,912)
(2,305,481)
(9,283,393)
-
-
-
(6,977,912)
(2,305,481)
(9,283,393)
50,000
19,526,413
9,513,433
29,089,846
-
-
-
-
-
(1,585,294)
(2,858,628)
(4,443,922)
7,388,793
-
-
7,388,793
-
-
442,627
442,627
7,388,793
-
442,627
7,831,420
In 2014 the Group changed its segment reporting from one operating segment to three separately identifiable
operating segments. Consequently the 2013 segment reporting note has been revised to reflect the same
reporting format as 2014, refer to table above.
Revenue from external customers by geographical location of production
Australia
Non-current assets by geographical location
Australia
2014
$
2013
$
3,718,102
-
2014
$
2013
$
69,484,821
19,871,442
Major Customers
There are two customers with revenue exceeding 10% of the group’s total oil and gas sales revenue.
Revenue from one customer represents $2,491,694 or 67% of the group’s total oil and gas revenues (2013:
$nil). Revenue from one customer represents $1,226,408 or 33% of the group’s total oil and gas revenues
(2013: $nil).
70
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F O R T H E Y E AR E N D E D 30 J U N E 2014
23.
Parent entity information
(a) Summary financial information
The individual financial statements for the parent entity show the following aggregate amounts:
Statement of financial position
2014
$
2013
$
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
9,188,446
10,674,415
11,070,840
10,344,885
20,259,286
21,019,300
(3,118,556)
(2,948,174)
(4,723,544)
(2,948,174)
15,535,742
18,071,126
155,223,040
130,258,022
14,448,695
10,132,938
(154,135,993)
(122,319,834)
15,535,742
18,071,126
(31,816,159)
(12,389,760)
(31,816,159)
(12,389,760)
(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 was entered into by Central Petroleum PVD Pty Ltd (Borrower) in February 2014, 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 Palm valley 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 Palm Valley and
Dingo assets (such as Surprise) are not subject to a cash sweep or other restrictions under the Facility where no
defaults exist.
(c) Contingent assets and liabilities of the parent entity
There are no contingent assets.
Contingent liabilities exist in respect of legal action with Mr John Heugh. Details are set out in
Note 28 (a). This case is separate to the case disclosed in note 34(ii).
(d) Commitments of the parent entity
Operating lease commitments of the parent entity are set out in note 29 (b).
71
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F O R T H E Y E AR E N D E D 30 J U N E 2014
24. Related party transactions
(a) Parent entity
The parent entity is Central Petroleum Limited.
(b) Subsidiaries
The consolidated financial statements include the financial statements of Central Petroleum Limited and the
subsidiaries listed in the following table.
Name of entity
Place of
Incorporation
Class of
Shares
Equity holding
2014
2013
Merlin Energy Pty Ltd
Merlin West Pty Ltd
Western Australia
Western Australia
Helium Australia Pty Ltd
Victoria
Ordiv Petroleum Pty Ltd
Western Australia
Frontier Oil & Gas Pty Ltd
Western Australia
Central Green Pty Ltd
Western Australia
Central Geothermal Pty Ltd
Western Australia
Central Petroleum Services Pty Ltd
Western Australia
Central Petroleum PVD Pty Ltd
Queensland
Central Petroleum (N.T) Pty Ltd
Queensland
Jarl Pty Ltd
Queensland
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
(c) Key management personnel
Disclosures relating to key management personnel are set out in note 25.
25. Key management personnel
(a) Key management personnel compensation
Short-term employee benefits
Post-employment benefits
Long-term benefits
Share based payments
%
100
100
100
100
100
100
100
100
100
100
100
%
100
100
100
100
100
100
100
100
-
-
-
2014
$
2013
$
3,257,142
2,679,880
210,954
40,581
172,373
22,404
2,268,975
2,129,081
5,777,652
5,003,738
Detailed remuneration disclosures are provided in the remuneration report on pages 21 to 32.
72
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F O R T H E Y E AR E N D E D 30 J U N E 2014
25. Key management personnel (continued)
(b) Equity instrument disclosures relating to key management personnel
(i) Options provided as remuneration and shares issued on exercise of such options
Details of options provided as remuneration and shares issued on the exercise of such options, together with the
terms and conditions of the options, can be found in the remuneration report on pages 21 to 32.
(ii) Option holdings
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
Other
changes
Held at
date of
departure
Balance at
end of
year
Vested and
exercisable
Unvested
Non-Executive Directors
Andrew Whittle
2014
2013
William Dunmore
2014
2013
Wrixon Gasteen
2014
2013
4
Henry Askin
2014
2013
1
Robert Hubbard
2014
2013
2
Tom Wilson
2014
2013
Peter Moore
3
2014
2013
900,000
-
-
900,000
280,000
280,000
1,000,000
-
-
-
-
1,000,000
-
-
-
-
-
-
-
-
(280,000)
-
-
-
N/A
N/A
N/A
N/A
668,000
1,300,000
N/A
N/A
N/A
N/A
N/A
N/A
-
N/A
-
N/A
-
N/A
-
-
N/A
-
N/A
-
N/A
-
-
N/A
-
N/A
-
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
1,968,000
N/A
N/A
N/A
N/A
N/A
N/A
900,000
900,000
300,000
600,000
300,000
600,000
-
280,000
-
280,000
-
280,000
1,000,000
1,000,000
333,334
333,334
666,666
666,666
N/A
N/A
-
N/A
-
N/A
-
N/A
N/A
1,101,333
N/A
866,667
-
N/A
-
N/A
-
N/A
-
N/A
-
N/A
-
N/A
1 Appointed 6 December 2013
3 Appointed 14 April 2014
2 Appointed 31 March 2014
4 Retired 20 November 2012
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F O R T H E Y E AR E N D E D 30 J U N E 2014
25.
Key management personnel (continued)
(b) Equity instrument disclosures relating to key management personnel
Balance at
start of year
Granted as
compensation
Exercised
Other
change
Held at date of
departure
Balance at
end of
year
Vested and
exercisable
Unvested
Executive Directors and Other Key
Management Personnel
1
Richard Cottee
2014
2013
Michael
Herrington
2014
2013
Daniel White
2014
2013
Bruce Elsholz
2014
2013
Leon Devaney
2014
2013
Michael Bucknill
2
2014
2013
Robert Willink
3
2014
2013
34,584,407
-
-
34,584,407
900,000
1,800,000
-
900,000
929,200
929,200
733,334
-
600,000
600,000
-
-
-
N/A
-
N/A
570,000
-
560,000
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(19,200)
-
-
-
-
-
-
-
-
-
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
34,584,407
9,683,634
24,900,773
34,584,407
9,683,634
24,900,773
2,700,000
300,000
2,400,000
900,000
300,000
600,000
1,643,334
1,643,334
929,200
929,200
1,170,000
1,170,000
600,000
600,000
560,000
560,000
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1
34,584,407 unlisted options exercisable at $0.45 on or before 15 November 2015 and 15 November 2017 were issued to FEP on 8 August 2012,
a company in which Richard Cottee has a 50% beneficial equity interest.
2
100,000 options issued 17 July 2014
120,000 options issued 17 July 2014
3
74
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F O R T H E Y E AR E N D E D 30 J U N E 2014
25. Key management personnel (continued)
(iii) 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 On market purchases
Received on
exercise of
options
Net change
other
Held at
date of
departure
Held at
end of
year
Non-Executive Directors
Andrew Whittle
2014
2013
William Dunmore
2014
2013
Wrixon Gasteen
2014
2013
4
Henry Askin
2014
2013
1
Robert Hubbard
2014
2013
2
Tom Wilson
2014
2013
3
Peter Moore
2014
2013
133,680
80,000
183,743
155,334
104,000
-
N/A
774,546
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
64,100
N/A
-
N/A
-
53,680
-
-
-
104,000
-
-
-
-
-
-
-
-
N/A
N/A
Executive Directors and Other Key Management Personnel
Richard Cottee
-
N/A
2014
2013
Michael Herrington
2014
2013
Daniel White
2014
2013
Bruce Elsholz
2014
2013
Leon Devaney
2014
2013
5
Michael Bucknill
2014
2013
5
Robbert Willink
2014
2013
208,683
-
200,000
-
288,000
288,000
-
-
110,000
-
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
-
-
31,000
N/A
-
-
-
N/A
-
208,683
-
200,000
-
-
-
-
-
110,000
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
N/A
N/A
133,680
133,680
-
28,104
(7,000)
-
N/A
N/A
183,743
183,743
N/A
N/A
97,000
104,000
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
N/A
774,546
N/A
N/A
N/A
N/A
64,100
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
208,683
208,683
200,000
200,000
288,000
288,000
-
-
110,000
110,000
31,000
N/A
-
N/A
1 Appointed 6 December 2013
3 Appointed 14 April 2014
5 Appointed 1 July 2013
2 Appointed 31 March 2014
4 Retired 20 November 2012
75
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25. Key management personnel (continued)
(c) Other transactions with key management personnel
(i) During the year ended 30 June 2014 the consolidated entity paid $24,476 (2013: $69,629) to Dunmore
Consulting, a business in which Mr Dunmore is the principal, for the provision of technical and corporate
advisory services. This transaction was on normal commercial terms and conditions no more favourable than
those available to other parties.
(ii) During the year ended 30 June 2014 the consolidated entity paid $nil (2013: $58,000) to Jabiru Energy
Development and Innovation Pty Ltd, a business in which Mr Herrington is the principal, for the provision of
corporate advisory services prior to his appointment as Chief Operating Officer of the Company. This
transaction was on normal commercial terms and conditions no more favourable than those available to other
parties.
(iii) During the year ended 30 June 2014 the consolidated entity paid $nil (2013: $168,000) to Ikon Corporate Pte
Ltd, a business in which Mr Gasteen is a director, for the provision of corporate advisory services including the
sale of Merlin Coal Pty Ltd. This transaction was on normal commercial terms and conditions no more
favourable than those available to other parties.
(iv) FEP has provided the services of Richard Cottee on the basis of a secondment to the Company. As such
compensation is made to FEP in line with FEP’s Intercompany Services Agreement shown on page 28. Richard
Cottee has a 50% beneficial equity interest in FEP.
During the year ended 30 June 2014 FEP has received compensation of $516,470 (2013: $516,470).
26. Reconciliation of loss after income tax to net cash outflow from operating activities
2014
$
2013
$
Loss after income tax
Adjustments for:
Depreciation and amortisation
Share-based payments
Income tax expense
Write off of property, plant and equipment
Write off of exploration assets
Gain on sale of investment
(10,857,986)
(9,283,393)
1,127,155
456,880
2,818,231
2,168,210
(4,107,498)
-
-
-
-
503,703
1,657,600
(1,744,796)
Changes
activities:
in assets and
liabilities relating
to operating
(Increase) / decrease in trade and other receivables
3,981,516
(5,356,057)
Decrease / (increase) in inventories
(Increase) in exploration assets
(Decrease) / increase in trade and other payables
Increase / (decrease) in provisions
Net cash inflow/(outflow) from operating activities
(965,702)
76,159
(650,000)
(500,000)
7,847,852
(314,138)
1,284,193
183,366
477,761
(12,152,466)
76
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F O R T H E Y E AR E N D E D 30 J U N E 2014
27. Non-cash investing and financing activities
In 2014 the Group purchased 100% of Magellan Petroleum (NT) Pty Ltd ("MPNT") from Magellan Petroleum
Corporation. The consideration paid for the sale was $35,595,871 made up of $20,595,871 in cash and an
issue of 39,473,684 shares in Central Petroleum Limited with a fair value of $15,000,000. See note 33 for
further details.
In 2013, the remaining 20% interest in EP97 was acquired from Rawson Resources for consideration of 50
million ordinary shares in Central Petroleum Ltd ($6,888,793). Upon completion of the transaction, Central
holds a 100% interest in the permit.
28. Contingencies
(a) Contingent liabilities
(i) The consolidated entity had contingent liabilities at 30 June 2014 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 (2013: $1,000,000) within twelve months following the
commencement of any future commercial production from the permits.
(ii) On 29 November 2012 the Company was advised that Mr Heugh had commenced an action in the Supreme
Court of Western Australia against the Company and others for alleged false and defamatory statements of
and concerning Mr Heugh.
The Company is defending the action vigorously.
The claim is currently being funded pursuant to the Company’s Employment Practices Liability insurance.
The directors believe that a favourable outcome to the dispute is probable and no material amount will be
payable by the Company. This case is separate to the case disclosed in note 34(ii).
(b) Contingent assets
There were no contingent assets at 30 June 2014 (30 June 2013 - $nil).
2014
$
2013
$
29. Commitments
(a) Capital commitments
The consolidated entity has the following 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
(a)
32,976,497
15,447,000
-
-
24,000,000
12,903,000
72,423,497
12,903,000
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 them altogether and, as a result, obligations may be reduced or extinguished.
(a) $21,346,497 of this commitment relates to the Dingo gas field development funded by the Macquarie debt
facility.
77
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F O R T H E Y E AR E N D E D 30 J U N E 2014
29. Commitments (continued)
(b) Operating lease commitments
$
$
The consolidated entity, through its parent entity Central Petroleum
Limited, has non-cancellable operating leases for office premises in
Perth, 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
595,987
346,592
2,414,894
3,010,881
-
346,592
30.
Share based payments
(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.
78
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F O R T H E Y E AR E N D E D 30 J U N E 2014
30.
Share based payments (continued)
Expiry Date
Exercise
price1
Balance at
start of the
year
Number1
Granted
during the
year
Number
Exercised
during the
year
Number
2014
31 Mar 2014
31 Mar 2014
31 Mar 2014
31 Mar 2014
31 Mar 2014
31 Mar 2014
$1.110
$1.250
$1.400
$1.600
$1.850
300,000
300,000
300,000
300,000
300,000
$1.000
1,673,334
31 May 2015
$0.610
1,268,000
31 Oct 2015
$0.550
120,000
15 Nov 2015
15 Nov 2015
15 Nov 2015
12 May 2016
20 Jul 2016
19 Aug 2016
30 Aug 2016
$0.450
9,683,634
$0.450
$0.650
$0.600
$0.550
$0.575
$0.575
-
-
40,000
669,334
400,000
800,000
15 Nov2016
$0.475
2,318,668
Expired or
forfeited
during the
year
Number
(300,000)
(300,000)
(300,000)
(300,000)
(300,000)
(1,673,334)
-
-
-
-
-
-
-
-
(200,000)
Balance at
end of the
year
Number
Vested and
exercisable at
the end of the
year
-
-
-
-
-
-
N/A
N/A
N/A
N/A
N/A
N/A
1,268,000
1,268,000
120,000
9,683,634
4,354,334
207,000
40,000
669,334
400,000
600,000
120,000
9,683,634
4,354,334
-
40,000
669,334
400,000
600,000
-
-
-
-
2,318,668
2,318,668
400,000
400,000
24,900,773
1,800,000
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
4,379,334
(25,000)
207,000
-
-
-
-
-
-
-
30 Nov 2016
15 Nov 2017
15 Nov 2017
$0.475
400,000
$0.450
24,900,773
$0.475
-
1,800,000
Totals
47,873,748
6,386,334
(25,000)
(3,373,334)
50,861,748
19,853,970
Weighted average exercise price
$0.510
$0.460
$0.450
$1.210
$0.460
$0.470
Weighted average remaining contractual life (years) at the end of the year
2.60
1 On 27 September 2013 shareholders approved every 5 ordinary shares held be converted into 1 ordinary share (subject to rounding).
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F O R T H E Y E AR E N D E D 30 J U N E 2014
30.
Share based payments (continued)
Expiry Date
Exercise
price
Balance at
start of the
year
Number
Granted
during the
year
Number
Exercised
during the
year
Number
Expired or
forfeited
during the
year
Number
Balance at
end of the
year
Number
Vested and
exercisable at
the end of the
year
2013
31 Mar 2014
31 Mar 2014
31 Mar 2014
31 Mar 2014
31 Mar 2014
31 Mar 2014
31 May 2015
31 Oct 2015
15 Nov 2015
15 Nov 2015
12 May 2016
20 Jul 2016
19 Aug 2016
30 Aug 2016
15 Nov 2016
30 Nov 2016
15 Nov 2017
15 Nov 2017
$0.220
$0.250
$0.280
$0.320
$0.370
$0.200
$0.122
$0.110
$0.090
$0.090
$0.120
$0.110
$0.115
$0.115
$0.095
$0.095
$0.090
$0.090
1,500,000
1,500,000
1,500,000
1,500,000
1,500,000
8,366,666
6,340,000
600,000
-
-
300,000
5,646,665
2,000,000
-
-
-
-
-
-
-
-
48,418,169
6,833,332
-
-
-
-
-
-
-
-
-
-
-
-
-
(2,300,000)
-
-
-
-
-
-
-
-
-
-
(100,000)
-
1,500,000
1,500,000
1,500,000
1,500,000
1,500,000
8,366,666
6,340,000
600,000
48,418,169
6,833,332
200,000
3,346,665
-
-
-
2,000,000
4,000,000
12,993,335
6,000,000
-
-
-
-
-
124,503,864
13,666,668
-
(1,400,000)
(3,000,000)
-
-
-
-
(1,000,000)
-
-
4,000,000
11,593,335
2,000,000
124,503,864
13,666,668
1,500,000
1,500,000
1,500,000
1,500,000
1,500,000
8,366,666
6,340,000
600,000
48,418,169
6,833,332
200,000
3,346,665
2,000,000
3,000,000
11,593,335
1,500,000
-
-
Totals
53,746,666
193,422,033
(6,700,00)
(1,100,000)
239,368,699
99,698,167
Weighted average exercise price
$0.146
$0.090
$0.100
$0.097
$0.102
$0.119
Weighted average remaining contractual life (years) at the end of the year
3.630
(b) Employee options granted during the year
Options granted during the year ended 30 June 2014 and 30 June 2013 were valued using a binomial option pricing
model. The model inputs for option issued during the year included:
Grant date
Expiry date
Number of
options
Average
fair
value
per
option
Exercise
price
Price of
shares on
grant date
Estimated
volatility*
Risk free
interest
rate
Dividend
yield
2014
10 Jul 13
15 Nov 15
4,379,334
28 Nov 13
15 Nov 15
1,800,000
10 Apr 14
15 Nov 15
207,000
$0.047
$0.045
$0.055
$0.450
$0.475
$0.650
2013
19 Jul 12
19 Jul 12
19 Jul 12
15 Nov 15
48,418,169
$0.023
15 Nov 17
55,335,051
$0.027
15 Nov 17
69,168,813
$0.024
29 Nov 12
15 Nov 15
6,833,332
29 Nov 12
15 Nov 17
6,833,332
29 Nov 12
15 Nov 17
6,833,332
$0.039
$0.042
$0.045
$0.45
$0.45
$0.45
$0.45
$0.45
$0.45
$0.625
$0.320
$0.490
$0.625
$0.625
$0.625
$0.755
$0.755
$0.755
60% to 90%
45% to 65%
45% to 65%
2.73%
2.69%
2.79%
60% to 90%
60% to 90%
60% to 90%
50% to 80%
50% to 80%
50% to 80%
2.73%
2.77%
2.77%
2.73%
2.77%
2.77%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
* The estimated price volatility is based on the historical price volatility for the 12 months prior to the date of
granting of the options, adjusted for any expected changes to future volatility due to publicly available
information.
80
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F O R T H E Y E AR E N D E D 30 J U N E 2014
30.
Share based payments (continued)
(c) Expenses arising from share-based payment transactions
Total expenses arising from share based transactions recognised during the year were:
Options issued to directors and employees
2014
$
2013
$
2,818,231
2,168,210
31
Financial risk management
The consolidated entity’s principal financial instruments are cash and short-term deposits. The consolidated entity also
has other financial assets and liabilities such as trade receivables, trade payables and borrowings, which arise directly
from its operations. The consolidated entity’s risk management objective with regard to financial instruments and other
financial assets include gaining interest income and the policy is to do so with a minimum of risk.
(a) Credit Risk
The credit risk on financial assets of the consolidated entity which have been recognised in the statement of
financial position is generally the carrying amount, net of any provision for doubtful debts. The consolidated entity
trades only with recognised banks and Santos Ltd subsidiaries / operated joint ventures where the credit risk is
considered minimal.
The aging of the consolidated entity’s receivables at reporting date was:
Trade and other receivables
Gross
Past due: 0 – 30 days
Past due: 31 – 150 days
Past due: 151 – 365 days
2014
$
1,191,514
1,274,539
-
2013
$
6,778,095
31,878
-
2,466,053
6,809,973
Impairment
2014
$
2013
$
-
-
-
-
-
-
-
-
Based on historic default rates, the consolidated entity believes that no impairment allowance is necessary in
respect of receivables past due by up to 150 days.
The receivables at 30 June 2014 relate predominantly to the oil sales from Surprise West field and gas sales
from Palm Valley field. In addition amounts receivable exist from joint arrangement partner recharges and gst
refunds due from the Australian tax office. 100% of trade and other receivables have been received to date.
Credit risk also arises in relation to financial guarantees given to certain parties (see notes 23(b)). Such
guarantees are only provided in exceptional circumstances and are subject to specific board approval.
(b) Liquidity Risk
The following are the contractual maturities of financial assets and liabilities:
2014
Financial Assets
Cash and cash equivalents
Trade and other receivables
Other financial assets
Financial Liabilities
Trade and other payables
Macquarie debt facility
≤ 6 months
$
6 - 12
months
$
1 - 5 years
$
≥ 5 years
$
Total
$
10,330,474
2,466,053
2,423,185
15,219,712
-
-
-
-
-
-
-
-
(10,476,308)
-
-
(255,760)
-
(23,761,593)
(10,476,308)
(255,760)
(23,761,593)
81
-
-
-
-
-
-
-
10,330,474
2,466,053
2,423,185
15,219,712
(10,476,308)
(24,017,353)
(34,493,661)
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
31
Financial risk management (continued)
2013
Financial Assets
Cash and cash equivalents
Trade and other receivables
Other financial assets
Financial Liabilities
Trade and other payables
≤ 6 months
$
6 - 12
months
$
1 - 5 years
$
≥ 5 years
$
Total
$
1,308,307
6,809,973
215,015
8,333,295
(3,332,034)
(3,332,034)
-
-
-
-
-
-
-
-
1,639,604
1,639,604
-
-
-
-
-
-
-
-
1,308,307
6,809,973
1,854,619
9,972,899
(3,332,034)
(3,332,034)
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 had access to the following undrawn borrowing facilities at the end of the reporting period:
2014
$
2013
$
Macquarie debt facility (floating rate)
31(d)
24,426,000
-
(c)
Interest Rate Risk
The consolidated entity’s exposure to interest rate risk, which is the risk that a financial instrument’s value
will fluctuate as a result of changes in market interest rates and the effective weighted average interest
rates on classes of financial assets and financial liabilities, is as follows:
Consolidated
Weighted
Average
Effective
Interest Rate
Floating interest rate
Fixed interest
Non-interest
bearing
Total
2014
%
2013
%
2014
$
2013
$
2014
$
2013
$
2014
$
2013
$
2014
$
2013
$
Financial Assets:
Cash and
cash equivalents
Trade and other
receivables
Other financial
assets
0.9
0.8
10,330,474 1,308,307
-
-
0.6
0.5
-
-
-
-
10,330,474 1,308,307
Financial Liabilities:
Trade and other
payables
Interest bearing
liabilities
-
10.2
-
-
-
(24,017,353)
(24,017,353)
-
-
-
-
-
485,828
485,828
-
-
-
-
-
-
-
10,330,474
1,308,307
2,466,053
6,809,973
2,466,053
6,809,973
215,015
1,937,357
1,639,604
2,423,185
1,854,619
215,015
4,403,410
8,449,577
15,219,712
9,972,899
-
-
-
(10,476,308)
(3,332,034)
(10,476,308)
(3,332,034)
-
-
(24,017,353)
-
(10,476,308)
(3,332,034)
(34,493,661)
(3,332,034)
Net Financial
Assets/(Liabilities)
(14,368,879)
1,308,307
485,828
215,015
(6,072,898)
5,117,543
(19,273,949)
6,640,865
82
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
31
Financial risk management (continued)
Interest Rate Sensitivity
A sensitivity of 10 per cent 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 2013.
Profit or Loss
Equity
10% Increase 10% Decrease 10% Increase 10% Decrease
2014
Cash and cash equivalents
Interest bearing liabilities
15,456
255,779
(15,456)
(255,779)
2013
Cash and cash equivalents
Interest bearing liabilities
987
-
(987)
-
-
-
-
-
(d)
Financing Facilities
In February 2014, Central Petroleum PVD Pty Ltd entered into a Loan Facility Agreement (Facility)
with Macquarie Bank Limited (Macquarie). The Facility consists of 3 tranches totalling $50 million.
Tranches A and C total $20 million and were used for the acquisition of Palm Valley and Dingo gas
fields and related assets from Magellan. Tranche B accounts for the balance of the Facility (up to
$30 million) and is available to fund completion of the Dingo gas field, including all acquisition costs
and capitalised interest expenses. Tranche C ($5 million) is structured as a 2-year, interest only
bullet. Tranche A and B ($45 million in total) are structured as a 5 year partially amortising term
loan. The interest costs for each loan are based on fixed spreads over the periodic Bank Bill Swap
(BBSW) average bid rate. The interest rate for tranche B steps down on completion of the Dingo
project provided certain production hurdles or financial ratios are achieved. The Group does not
have any interest rate hedging arrangements in place. Central Petroleum Ltd can repay the Facility
in part or in whole at any time without a pre-payment penalty.
Under the terms of the Facility, the Group is required to comply with the following two key financial
covenants:
1) The Group Current Ratio is at least 1:1, excluding amounts payable under the Maquarie debt
facility and outstanding contributions to the Southern Georgina joint arrangement.
2) The Net Present Value with a 10% discount rate (NPV10) of forecasted net cash flow from
Palm Valley and Dingo limited by the sales of only Proved Developed Producing reserves,
divided by the outstanding loan amount must be greater than 1:1
The Group remains compliant with these and all other financial covenants under the Facility.
(e)
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 small 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.
(f)
Fair Values
The carrying amounts of cash, cash equivalents, financial assets and financial liabilities, approximate their
fair values.
83
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
32.
Interests in joint arrangements
Details of joint arrangements in which the consolidated entity has an interest are as follows:
Principal activities
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
Oil & gas exploration
2014
%
75.00
75.00
75.00
75.00
75.00
30.00
75.00
60.00
90.00
90.00
90.00
75.00
2013
%
75.00
75.00
75.00
75.00
75.00
30.00
75.00
60.00
90.00
90.00
90.00
75.00
EP82 (Santos)
EP105 (Santos)
EP106 (Santos)
EP107 (Santos)
EP112 (Santos)
EP125 (Santos)
RL3 & 4 (Santos) *
EP115 North Mereenie Block (Santos)
ATP909 (Total)
ATP911 (Total)
ATP912 (Total)
EP(A)147 (Santos)
Total = TOTAL GLNG Australia
Santos = Santos QNT Pty Ltd
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’ and Total’s 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.
* In line with the Company’s announcement of 31 July 2014, consolidated entity regained 100% ownership of
RL3 & 4.
84
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
32.
Interests in joint arrangements (continued)
The share in the assets and liabilities of the joint arrangements where less than 100% interest is held by the
Company are included in the consolidated entity’s statement of financial position in accordance with the
accounting policy described in note 1(b) under the following classifications:
Current assets
Cash and cash equivalents
Trade and other receivables
Inventory
Total current assets
Non-current assets
Property, plant and equipment
Other financial assets
Current liabilities
Trade and other payables
Joint Venture under contributions *
Accruals
2014
$
2013
$
807,914
45,500
362,958
1,216,372
176,900
9,300
186,200
353,355
4,305,514
38,221
4,697,090
51,373
12,822
-
64,195
-
7,200
7,200
128,515
322,058
63,555
514,128
Net liabilities
3,294,518
442,733
Joint arrangement contribution to loss before tax
Revenue
Expenses
Profit / (Loss) before income tax
11,112
(2,948,314)
(2,937,202)
313
(440,962)
(440,649)
* The Group is liable for the last 20% of the stage 1 expenditure, with Total funding the first 80%.
85
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
33. Business Combination
On 31 March 2014 the Group purchased 100% of Magellan Petroleum (NT) Pty Ltd ("MPNT") from Magellan
Petroleum Corporation, a NASDAQ Stock Exchange-listed oil and gas exploration and production company.
The Group identified the purchase of MPNT as a strategic acquisition for the CTP Group in line with delivering
strong growth from exploration and production across Central Australia. The acquisition provides Central with
infrastructure and production revenues.
The consideration paid for the sale was $35,595,871 made up of $20,595,871 in cash and an issue of
39,473,684 shares in Central Petroleum Limited with a fair value of $15,000,000. Transaction fees of $1,914,004
were incurred.
The provisional fair value allocation to the identifiable assets and liabilities is detailed below. To the extent that
the purchase consideration exceeds the aggregate of the fair value of the identifiable assets and liabilities of
MPNT, then goodwill has been recognised and recorded on acquisition.
Assets
Exploration assets
Property, plant & equipment
Trade and other receivables
Inventory
Assets held for sale
Liabilities
Provisions for liabilities and charges
Provision for deferred tax
Net assets at fair value
Goodwill arising on acquisition
Purchase consideration transferred
Cash
Issued share capital
Provisional
fair value
recognised on
acquisition
$
650,000
39,027,558
63,973
534,689
1,000,000
41,276,220
5,479,121
4,107,498
9,586,619
31,689,601
3,906,270
35,595,871
20,595,871
15,000,000
35,595,871
From the date of acquisition, MPNT contributed a profit of $349,223 to the results of the Group. If the
combination had taken place at the beginning of the financial year, revenue from continuing operations for the
Group would have been $4,616,062 and the loss from the continuing operations for the Group would have been
$(12,013,404).
86
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
N O T E S T O T H E C O N S O L I D AT E D F I N AN C I AL S T AT E M E N T S
F O R T H E Y E AR E N D E D 30 J U N E 2014
33. Business Combinations (continued)
Contingent Consideration
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 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 price hurdles are in excess of the current gas prices received from
the Palm Valley gas field and escalate annually with CPI. The Gas Price Bonus Amount is calculated as 25% of
the difference between the weighted average price of gas actually sold in a Contract Year and the gas price
bonus hurdle applicable to that Contract Year (after adjusting for CPI), multiplied by the actual volume of gas
originating and sold from the Palm Valley gas field .
The weighted average price of gas sold from the Palm Valley gas field is currently below the Gas Price Bonus
hurdle price and therefore no gas price bonus is payable (or anticipated to be payable) at this time. Given
current NT 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 significantly higher priced
markets eventuate, this contingent liability will be revisited. Importantly, any future payment of the Gas Price
Bonus would likely only occur where sales and revenues from the Palm Valley gas field materially exceed our
acquisition assumptions.
34
Events occurring after the reporting period
Subsequent to 30 June 2014 the following events have occurred:
(i)
Share placement
On 24 September 2014 the Company agreed to place 20 million shares at $0.30 per share with
institutional investors in Australia and Hong Kong raising $6 million. The $0.30 issue price represents a
1.7% discount to the 10-day VWAP. Settlement of the placement is due on 1 October 2014.
(ii)
John Heugh Legal Case
On 5 September 2014 Mr Justice Le Miere handed down his judgement on the case alleging unfair dismissal of
John Heugh by the board of Central Petroleum in the first quarter of 2012.
The Court found that Mr Heugh seriously breached his employment contract by failing to comply with the
directions of the board by putting pressure on Trevor Shortt not to accept responsibility for farmouts, and by
failing to ensure the proper implementation of Central Petroleum’s policies, procedures and systems and in
particular its code of conduct. However, the Court held that Mr Heugh remedied those breaches.
The Court found that it was not reasonable for the board to terminate Mr Heugh’s contract and awarded him
damages of $1,598,298 inclusive of interest, costs are yet to be determined. In line with AASB 110 Events
after the Reporting Period and AASB 137 Provisions, Contingent Liabilities and Contingent Assets a provision
has been recognised.
The Company will not initiate an appeal process of this decision and has paid the proportion of the damages
not covered by insurance.
87
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
DIRECTORS’ DECLARATION
In the directors’ opinion:
a)
the financial statements and notes set out on pages 40 to 87 of the Consolidated Entity are in
accordance with the Corporations Act 2001 (Cth), including:
(i) complying with Accounting Standards, the Corporations Regulations 2001 (Cth) and other
mandatory professional reporting requirements, and
(ii) giving a true and fair view of the Consolidated Entity’s financial position as at 30 June 2014
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 2014.
This declaration is made in accordance with a resolution of the directors of Central Petroleum Limited:
Richard Cottee
Managing Director
Brisbane, 30 September 2014
88
Independent auditor’s report to the members of Central
Petroleum Limited
Report on the financial report
We have audited the accompanying financial report of Central Petroleum Limited (the company),
which comprises the consolidated statement of financial position as at 30 June 2014, the consolidated
statement of comprehensive income, consolidated statement of changes in equity and consolidated
statement of cash flows for the year ended on that date, a summary of significant accounting policies,
other explanatory notes and the directors’ declaration for Central Petroleum Limited (the consolidated
entity). The consolidated entity comprises the company and the entities it controlled at year’s end or
from time to time during the financial year.
Directors’ responsibility for the financial report
The directors of the company are responsible for the preparation of the financial report that gives a
true and fair view in accordance with Australian Accounting Standards and the Corporations Act 2001
and for such internal control as the directors determine is necessary to enable the preparation of the
financial report that is free from material misstatement, whether due to fraud or error. In Note 1, the
directors also state, in accordance with Accounting Standard AASB 101 Presentation of Financial
Statements, that the financial statements comply with International Financial Reporting Standards.
Auditor’s responsibility
Our responsibility is to express an opinion on the financial report based on our audit. We conducted
our audit in accordance with Australian Auditing Standards. Those standards require that we comply
with relevant ethical requirements relating to audit engagements and plan and perform the audit to
obtain reasonable assurance whether the financial report is free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures
in the financial report. The procedures selected depend on the auditor’s judgement, including the
assessment of the risks of material misstatement of the financial report, whether due to fraud or error.
In making those risk assessments, the auditor considers internal control relevant to the consolidated
entity’s preparation and fair presentation of the financial report in order to design audit procedures
that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the
effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of
accounting policies used and the reasonableness of accounting estimates made by the directors, as well
as evaluating the overall presentation of the financial report.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for
our audit opinion.
Independence
In conducting our audit, we have complied with the independence requirements of the Corporations
Act 2001.
Auditor’s opinion
In our opinion:
PricewaterhouseCoopers, ABN 52 780 433 757
Riverside Centre, 123 Eagle Street, BRISBANE QLD 4000, GPO Box 150, BRISBANE QLD 4001
T: +61 7 3257 5000, F: +61 7 3257 5999, www.pwc.com.au
Liability limited by a scheme approved under Professional Standards Legislation.
89
(a)
the financial report of Central Petroleum Limited is in accordance with the Corporations Act
2001, including:
(i)
(ii)
giving a true and fair view of the consolidated entity's financial position as at 30 June
2014 and of its performance for the year ended on that date; and
complying with Australian Accounting Standards (including the Australian Accounting
Interpretations) and the Corporations Regulations 2001.
(b)
the financial report and notes also comply with International Financial Reporting Standards as
disclosed in Note 1.
Report on the Remuneration Report
We have audited the remuneration report included in pages 21 to 32 of the directors’ report for the
year ended 30 June 2014. The directors of the company are responsible for the preparation and
presentation of the remuneration report in accordance with section 300A of the Corporations Act
2001. Our responsibility is to express an opinion on the remuneration report, based on our audit
conducted in accordance with Australian Auditing Standards.
Auditor’s opinion
In our opinion, the remuneration report of Central Petroleum Limited for the year ended 30 June 2014
complies with section 300A of the Corporations Act 2001.
Matters relating to the electronic presentation of the audited
financial report
This auditor’s report relates to the financial report and remuneration report of Central Petroleum
Limited (the company) for the year ended 30 June 2014 included on Central Petroleum Limited’s web
site. The company’s directors are responsible for the integrity of Central Petroleum Limited’s web site.
We have not been engaged to report on the integrity of this web site. The auditor’s report refers only to
the financial report and remuneration report named above. It does not provide an opinion on any
other information which may have been hyperlinked to/from the financial report or the remuneration
report. If users of this report are concerned with the inherent risks arising from electronic data
communications they are advised to refer to the hard copy of the audited financial report and
remuneration report to confirm the information included in the audited financial report and
remuneration report presented on this web site.
PricewaterhouseCoopers
Michael Shewan
Partner
90
Brisbane
30 September 2014
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
AS X AD D I T I O N AL I N F O R M AT I O N AT 1 9 S E P T E M B E R 2 0 14
Details of quoted securities as at 19 September 2014:
Top holders
The 20 largest registered holders of the quoted securities as at 19 September 2014 were:
Ordinary fully paid shares
Name
No. of Shares
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
Magellan Petroleum Australia Pty Ltd
Citicorp Nominees Pty Limited
Macquarie Bank Limited
HSBC Custody Nominees Australia Limited
Mr Gerard Pieter Tom Van Brugge
J P Morgan Nominees Australia Limited
National Nominees Limited
BNP Paribas Noms Pty Ltd
Marford Group Pty Ltd
Mr Mark Philip Shawcross
Mr James Donald Bruce Cochrane + Mrs Joan Elizabeth Cochrane
Franze Holdings Pty Ltd
John Cresswell Leigh + Dulcie Lynette Leigh
Mr Geoffrey Rol
RBJ Nominees Pty Ltd
Advent Energy Ltd
EPS Management Pty Ltd
Chembank Pty Ltd
Madeiros Pty Ltd
Franze Holdings Pty Limited
39,473,684
14,639,627
10,000,000
8,885,924
4,000,000
3,788,784
3,448,363
3,361,163
2,966,485
2,910,000
2,307,580
2,046,546
1,746,500
1,736,050
1,600,000
1,250,000
1,232,051
1,200,000
1,103,146
1,098,546
%
11.32
4.20
2.87
2.55
1.15
1.09
0.99
0.96
0.85
0.83
0.66
0.59
0.50
0.50
0.46
0.36
0.35
0.34
0.32
0.32
108,794,474
31.20
Distribution schedule
The distribution schedule of the ordinary fully paid shares as at 19 September 2014 was:
Range
Holders
Units
%
1
1,001
5,001
10,001
100,001
- 1,000
- 5,000
- 10,000
- 100,000
- Over
923
3,021
1,573
3,058
487
505,232
8,362,131
12,519,286
102,564,636
224,767,672
0.14
2.40
3.59
29.41
64.46
Total
9,062
348,718,957
100.00
Geographic Breakdown
The geographic distribution schedule of the ordinary fully paid shares as at 19 September 2014 was:
Location
Australia
Overseas
Holders
8,797
265
Units
335,583,482
13,135,475
%
96.23
3.77
Total
9,062
348,718,957
100.00
Substantial shareholders
As at 19 September 2014, there is one substantial shareholders in the Company.
Name
No. of Shares
%
Magellan Petroleum Australia Pty Ltd
39,473,684
11.32
91
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
AS X AD D I T I O N AL I N F O R M AT I O N AT 1 9 S E P T E M B E R 2 0 14
Restricted Securities
As at 19 September 2014, the Company had no restricted securities.
Unmarketable parcels
Holdings less than a marketable parcel of ordinary shares (being 1,493 shares as at 19 September 2014):
Holders
Units
1,357
1,042,140
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.
92
C E N T R AL P E T R O L E U M L I M I T E D
AB N 7 2 0 8 3 2 5 4 3 0 8
INTERESTS IN PETROLEUM PERMITS AND LICENCES AT 29 SEPTEMBER 2014
Permits and Licences Granted
Tenement
Location
Operator
Amadeus Basin NT
Pedirka Basin NT
Pedirka Basin NT
Amadeus/Pedirka Basin NT
Amadeus Basin NT
Amadeus/Pedirka Basin NT
Amadeus Basin NT
EP 82**/***
EP 93
EP 97
EP 105**/***
EP 106**/***
EP 107**/***
EP 112**/***
EP 115
(excl.North
Mereenie Block) Amadeus Basin NT
EP 115 (North
Mereenie Block)
**/***
EP 125 **/***
OL3
L6
L7
RL3*
RL4*
ATP 909 **
ATP 911 **
ATP 912 **
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Georgina Basin QLD
Georgina Basin QLD
Georgina Basin QLD
CTP Consolidated Entity
Beneficial
Registered
Interest (%)
Interest (%)
60
75
100
100
100
100
60
75
60
75
60
75
60
75
Santos
Santos#
Central
Santos
Santos
Santos
Santos
Central
100
Santos
Santos
Central
Central
Central
Central
Central
Central
Central
Central
60
30
100
100
100
75
75
90
90
90
100
60
30
100
100
100
100
100
90
90
90
Other JV Participants
Participant Name
Beneficial
Interest (%)
40
Santos
Santos
Santos
Santos
Santos
Santos
Santos
Total
Total
Total
40
40
40
40
40
70
10
10
10
Permits and Licences Under Application
Tenement
Location
Operator
EPA 92
EPA 111
EPA 120
EPA 124
EPA 129
EPA 130
EPA 131
EPA 132
EPA 133
EPA 137
EPA 147***
EPA 149
EPA 152
EPA 160
EPA 296
PELA 77
Lander Trough NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Lander Trough NT
Pedirka Basin NT
Pedirka Basin NT
Georgina Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Lander Trough NT
Lander Trough NT
Pedirka Basin SA
Pipeline Licences
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Santos
Central
Central
Central
Central
Central
CTP Consolidated Entity
Beneficial
Registered
Interest (%)
Interest (%)
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
60
75
100
100
100
100
100
100
100
100
100
100
Other JV Participants
Participant Name
Beneficial
Interest (%)
Santos
40
Pipeline Licence
Location
Operator
PL30
Amadeus Basin NT
Central
CTP Consolidated Entity
Beneficial
Registered
Interest (%)
Interest (%)
100
100
Other JV Participants
Participant Name
Beneficial
Interest (%)
* in line with the Company’s announcement of 31 July 2014, a 100% beneficial interest is in favour of certain wholly owned Company subsidiaries for RL3 and
RL4 with registered interests to follow in the normal course.
** Santos’ and Total’s right to earn and retain participating interests in the 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.
*** in line with the Company’s announcement of 31 July 2014, an additional 15% beneficial interest is in favour of Santos with registered interests to follow in
the normal course.
93