2015
Annual Report
Central Petroleum Limited
ABN 72 083 254 308
TABLE OF CONTENTS
Corporate Directory ........................................................................................................................... 1
Chairman’s Letter ............................................................................................................................... 2
Managing Director’s Letter ................................................................................................................ 3
Directors’ Report ................................................................................................................................ 4
Auditor’s Independence Declaration ............................................................................................... 35
Corporate Governance Statement ................................................................................................... 36
Financial Report
Consolidated Statement of Profit or Loss and Other Comprehensive Income ...................... 38
Consolidated Statement of Financial Position ........................................................................ 39
Consolidated Statement of Changes in Equity ....................................................................... 40
Consolidated Statement of Cash Flows .................................................................................. 41
Notes to the Consolidated Financial Statements ................................................................... 42
Directors' Declaration ...................................................................................................................... 84
Independent Auditor's Report ......................................................................................................... 85
ASX Additional Information .............................................................................................................. 87
Interests in Permits and Pipeline Licences ....................................................................................... 89
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
CORPORATE DIRECTORY
DIRECTORS
Robert Hubbard FCA, Non‐executive Chairman
Andrew P Whittle BSc (Hons), Non‐executive Director
Richard I Cottee BA, LLB (Hons), Managing Director and Chief Executive Officer
Wrixon F Gasteen BE (Hons), MBA (Dist), Non‐executive Director
J. Thomas Wilson BSc, MSc, Non‐executive Director
Peter S Moore BSc (Hons1), MBA, PhD, Non‐executive Director
GROUP GENERAL COUNSEL AND JOINT COMPANY SECRETARY
Daniel C M White LLB, BCom, LLM
JOINT COMPANY SECRETARY
Joseph P Morfea FAIM, GAICD
REGISTERED OFFICE
Level 32, 400 George Street, Brisbane, Queensland 4000
Telephone: +61 7 3181 3800
Facsimile:
+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 under the code CTP.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
1
CHAIRMAN’S LETTER
A MESSAGE FROM ROBERT HUBBARD
Dear Fellow Shareholder
This is my first letter to you as Chairman of Central Petroleum Limited and I look forward to seeing many of you at our upcoming AGM.
The Annual Report is necessarily a scorecard for the past year and our operating and financial review draws out the many activities and
outcomes that your company has achieved throughout the year. In particular though, Central responded quickly to the oil price dive with the
necessary cost reductions, closure of Surprise and the use of alternate funding sources rather than equity placements which would dilute
our many long term loyal shareholders. We have not accessed the equity markets since this time last year in an effort to preserve the value
of our existing shareholders wherever possible and in fact only once in the last 24 months. The acquisition of Mereenie should now make
Central cash flow positive before elective exploration expenditure after completion of the acquisition.
However, the real achievement for the year is the continued transition of your Company from opportunistic explorer to a substantial domestic
gas producer. In 2014 we acquired the Magellan assets, in 2015 we completed the development and commissioned Dingo and concluded the
year with the acquisition of 50 percent of the Mereenie oil and gas field, where we are now the Operator. Our financial performance over
the 2015 financial year reflects these transitional dynamics as we developed gas production and pipeline infrastructure, ramped up our
contracted sales, increased equity accounted reserves and consolidated substantial operations under Central’s Operatorship. We are now
running on all cylinders with fixed‐price gas contracts underpinning operations and financing, and significant potential upside exposure
through uncontracted gas reserves.
All of this change has been achieved with an exemplary safety and environmental performance and a real commitment to the local
communities within which we operate. We are passionate about making a difference for those communities and increasing the participation
of traditional owners in our activities and generally at Alice Springs. Taking the employment at Palm Valley and Dingo before Central assumed
operatorship, 9 percent were indigenous employees and 88 percent were employed from outside the local area. Under our operatorship,
some 22.5 percent of our operating employees are indigenous and the number employed within the local area has increased to 40 percent.
When NEGI occurs those employed locally should see a further increase to well over the majority.
Looking to the future, Richard Cottee and his executive team have positioned your Company to take full advantage of the North East Gas
Interconnector (NEGI). Central has played a leadership role in the promotion of NEGI, a pipeline that will not only provide markets for our
reserves and significant exploration potential but also a catalyst for microeconomic reform in the gas sector. We grow increasingly confident
that NEGI should become a reality.
Central's achievements are a team effort and I would like to thank my colleagues on the Board, the senior executives and rest of the team at
Central. In particular, we all appreciate the leadership and guidance that Andy Whittle has provided as Chairman until recently. Andy will
step down from the board at the upcoming AGM and his leadership and guidance has been instrumental to the transformation of Central.
We wish Andy well with his future endeavours.
Finally, my last thank you is to you, our shareholders for your ongoing support and encouragement.
Best wishes
Robert Hubbard
Chairman
Brisbane
23 September 2015
2
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
MANAGING DIRECTOR’S LETTER
Dear Fellow Shareholder
DOMESTIC GAS MARKET – THE BRIDGE OVER TROUBLED WATERS
The last 12 months has seen the industry face difficult times (not seen since the late 1980’s) with Brent Crude Oil Price dropping over
50 percent in that period. This has been the prime cause of the share price drop of all oil and gas companies with the ASX Energy Index
dropping around 40 percent in the last 12 months. For Central the major impact has been that the access to the equity markets have either
become too expensive or difficult to access. In the last 24 months Central has only raised $6 million from the equity markets yet at the same
time has acquired the gas fields at Palm Valley and Dingo and 50 percent interest in the Mereenie oil and gas field as well as constructing the
Dingo gas field and the associated pipeline to Alice Springs.
Two years ago, Central embarked on a strategy to become a significant gas producer in domestic gas market. This culminated in the purchase
of the Dingo and Palm Valley gas fields last year and this year in the 50 percent acquisition of the Mereenie Field together with assumption
of operatorship of that field. In April last year the AFR reported that Central was agitating for the Northern Territory to be interconnected
with the Eastern Seaboard gas markets. By October this concept was endorsed at the Council of Australian Governments (COAG) Meeting
and in this year’s Federal Budget concessional loans were provided for what is now called the North East Gas Interconnector (NEGI). The
process was narrowed down to four bidders in April and two of the four bidders have publicly stated that they will build NEGI without
government support. Final bids have to be lodged by the end of September with a final decision around the end of October this year. With
no government funding being needed, the real question is not whether it is going to be built but whether what is built is capacity constrained
or capable of being cheaply upgraded once further reserves are discovered.
Regardless of which route is selected your company will be one of the three initial company’s whose gas will be transported through NEGI.
Fields under Central’s operatorship will contribute the majority of the gas. Any gas we sell will be sold in $A and indexed to Australian
inflation fixed for up to 10 years. Whilst the oil price has halved in the last 12 months (and with some gas prices linked to oil), the domestic
gas prices as reflected in the Wallumbilla Hub Spot Price has risen by over 200 percent. The opportunity for the company to secure its future
on record high domestic contracts over the whole of the next resources cycle beckons. Surely a bridge over the troubled waters.
With our 200,000 square kilometres of exploration acreage predominantly gas prone having an access to market for that acreage upon
exploration success must surely re‐rate the value of that acreage.
Central has presently 230 PJ of gas presently discovered available for NEGI even before our $10 million Pre‐NEGI programme’s results are
known. Central has been involved in marketing this gas and has been given indicative tariffs for the NEGI pipeline from the various
proponents. Using that information the NPV of that 230 PJ is worth over three times our present market capitalisation. As NEGI approaches
its first gas stage this NPV increases.
Central has existing installed capacity to deliver to the NEGI pipeline of over 20 PJ pa and so not much new built capital will be required
before first gas. The capital costs of connecting into NEGI will be low and able to be accommodated within the existing financial
accommodation.
In summary your company is positioned to take advantage of the historically high domestic gas prices at a time of cost‐deflation occasioned
by the commodity downturn. A virtuous cycle if ever there was one.
Richard Cottee
Managing Director
Brisbane
23 September 2015
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
3
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
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 2015.
DIRECTORS
The names of the Directors of the Company in office during the financial year and until the date of this report are set out below. Directors
were in office for this entire period unless otherwise stated.
Robert Hubbard
Andrew P Whittle
Richard I Cottee
Wrixon F Gasteen
J. Thomas Wilson
Peter S Moore
William J Dunmore (retired, effective 26 November 2014)
Michael R Herrington (retired, effective 26 November 2014)
PRINCIPAL ACTIVITIES
The principal activities of the Consolidated Entity constituting Central Petroleum Limited and the entities it controls consists of development,
production, processing and marketing of hydrocarbons and associated exploration.
DIVIDENDS
No dividends were paid or declared during the financial year (2014: $Nil). No recommendation for payment of dividends has been made.
OPERATING AND FINANCIAL REVIEW
Operating Highlights
The Company’s focus for the year was as follows:
NEGI project continues to gain momentum.
Mereenie acquisition announced with subsequent completion and Operatorship assumed.
Dingo development project completed on time and under budget.
Palm Valley produced 1.2 PJ of gas in the financial year. Palm Valley responded to Northern Territory wide gas interruption within
hours to help offset loss of supply.
Drilling of two Southern Georgina unconventional gas exploration wells prior to wet season.
Inaugural reserve bookings to Central across three fields.
Progressed evaluation of Stage 1 exploration results in the Southern Amadeus Basin, principally wireline logging of the Mt Kitty gas
well, and integrating ~1,580 km 2D seismic with potential field and outcrop data. This is to locate the planned ~1,300 km 2D seismic
which Santos committed to under Stage 2, and is Operator of the farm‐in program.
Identified and progressed delineation of exploration targets beneath and near to the Palm Valley field.
Identified Dingo satellite leads and Palm Valley deep appraisal target.
Progressed evaluation of Ooraminna gas discovery.
Acquired and interpreted gravity data over Western Amadeus application areas and Wiso Basin, thus improving structural
definition.
Progressed negotiations on application areas in the Amadeus Basin and Wiso Basin.
4
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
Operating Result
The Consolidated Entity had an operating loss after income tax for the year ended 30 June 2015 of $27,731,000 (2014: loss of $10,858,000).
This result was recorded after expensing exploration expenditure totaling $7,656,000 (2014: $4,660,000) and impairments totaling
$12,092,000 ($2014: $Nil) due in part to the decrease in oil prices. Operating loss for the year before the foregoing expenditures and after
income tax was $7,983,000 (2014: Loss of $6,198,000). It should also be noted that gas sales revenues for the year reflect the anticipated
ramp‐up in sales from the Palm Valley gas field (contract sales began May 2015) and do not include the Take‐or‐Pay revenue associated with
the Dingo gas field ($2.2 million) which, under the terms of the Power and Water Corporation Gas Sales Agreement (PWC GSA), are payable
in January 2016 (refer Note 1(e)(i)).
Granted Petroleum Production and Retention Licences in which the Company has an interest.
Key results for the reporting period were:
Sales Volumes of 54,374 barrels of crude oil from Surprise (2014: 22,858 barrels) and 1,194 TJ of gas from Palm Valley (2014:
278 TJ). This was the first full year of production for Central from both fields. Whilst the Dingo gas field development was completed
on 1 April 2014, the field is awaiting physical tie‐in by the customer before physical production can commence.
Sales Revenue of $10.3 million up 77 percent on the previous financial year reflecting increased production. An average oil price
of A$93 was realised during the year down from A$142 in the prior corresponding period. Realised gas prices remain consistent
with the prior year.
Research and Development refunds totaling $7.32 million were recognised as other income (2014: $1.20 million). The refunds
recorded during this period comprise $3.25 million in respect of the financial year ended 30 June 2014 and $4.07 million in respect
of the financial year ended 30 June 2015 which is recognised as a receivable at year end as it was received in September 2015.
Underlying loss1 of $15.64 million. The statutory loss after tax was $27.73 million, up from a statutory loss of $10.86 million in the
previous financial year. The result included non‐cash impairment of the Surprise oil property amounting to $5.42 million and
impairment of previously capitalised exploration properties of $6.57 million caused primarily by the fall in oil prices.
Exploration expenditure of $7.66 million up from $4.66 million in the previous financial year reflecting increased drilling activities
in the Southern Georgina Basin.
1 Underlying loss after tax can be reconciled to statutory loss after tax as follows:
Statutory loss after tax
Add/(less):
Business combination transaction fees
Impairment of exploration assets
Impairment of oil producing properties
Impairment of real property
Underlying loss after tax
2015
$ million
(27.73)
2014
$ million
(10.86)
—
6.57
5.42
0.10
1.91
—
—
—
(15.64)
(8.95)
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
5
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
Financial Review
The Company continued its transformation from an exploration company to an exploration and production company during the year ended
30 June 2015. The increased underlying loss is largely reflective of increased exploration expenditure during the year associated with drilling
activities in the Southern Georgina Basin in a joint venture with Total.
Key Metrics
Net Sales Volumes
Oil (barrels)
Natural Gas (TJ)
Average realised oil price (A$ per barrel)
Sales revenue ($ million)
Underlying Loss1 ($ million)
Statutory loss (after tax)
Cash ($ million)
2015
2014
Year on Year
Change
53,925
1,194
92.93
10.31
15.64
27.73
3.52
17,489
267
142.47
3.72
8.95
10.86
10.33
211%
347%
(35%)
177%
(75%)
(155%)
(66%)
Sales Volumes
Sales volumes for both oil and gas increase substantially from 2014.
Surprise oil field: sales from the Surprise oil field increased by 211 percent from the prior year, reflecting its first full year of production. The
low oil prices and the remoteness of the Company’s Surprise oil field has led to the decision to temporarily shut‐in oil production from this
field in August 2015 to allow the Company to assess the re‐charge potential of the field. Should oil prices recover significantly in $A terms,
production can re‐commence after assessing the pressure build‐up.
Palm Valley gas field: sales under the Palm Valley GSA with Santos reflect its first full year of production (having been acquired by Central in
April 2014) and the anticipated ramp‐up in nominations through to May, from which point sales are anticipated to be consistent with the
1.71 PJ/year ongoing annual contract quantity. May 2015 was the first month in which sales reflected maximum daily contract quantities.
Dingo gas field: The PWC GSA (Power and Water Corporation Gas Sales Agreement) commenced on 1 April 2015, but is constrained awaiting
the customer’s physical tie‐in to the Dingo delivery point. For the 3 month period following commencement of the GSA on 1 April 2015, a
total of 150 TJ was sold from the Palm Valley gas field, with a total of 361 TJs subject to Take‐or‐Pay arrangements. In accordance with the
PWC GSA, revenue associated with Take‐or‐Pay during a calendar year is payable in January of the following year. For the current period,
$2.2 million in Take‐or‐Pay revenue will become payable in January 2016 and has therefore not been recognised in this reporting period
(refer Note 1(e)(i)).
Commodity Prices
In line with the decline in world crude oil prices, and partly offset by a lower Australian dollar, the average realised price per barrel of oil
declined 35 percent on the previous financial year. In financial terms this represented a reduction in revenue of approximately $2.7 million
based on 2015 oil sales.
Gas prices under the Palm Valley GSA and the PWC GSA generally reflect long‐term fixed gas pricing structures with CPI related escalation,
and are therefore not impacted by recent weakness in global energy markets.
Other Income
Research and Development refunds totaling $7.32 million were recognised as income (2014: $1.20 million). The 2015 income included
refunds in respect of the financial year ended 30 June 2014 of $3.25 million and $4.07 million in respect of the financial year ended 30 June
2015 which is recognised as a receivable at year end as it was received in September 2015.
General and Administrative Expenses
General and administrative expenses net of recoveries decreased from $2.52 million in fiscal year 2014 to $1.94 million in fiscal year 2015.
The decrease was a result of cost savings implemented in response to the lower oil prices and increased recoveries from both sole and joint
venture operations generated by increased activity.
6
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
Financial Review (continued)
Employee benefits and associated costs
Employee costs increased to $5.02 million from $3.1 million in the previous financial year. The increase reflects a full year of corporate, Palm
Valley and Dingo manpower.
EBITDAX
The Statutory Loss after tax was $27.73 million, up from $10.86 million in the previous financial year. The statutory loss was heavily impacted
by non‐cash impairment charges of $12.09 million and exploration expenditure of $7.66 million. The decrease in EBITDAX was primarily due
to higher research and development refunds of $6.13 million and lower business combination costs of $1.91 million. These were partly offset
by lower oil prices.
Loss before interest, tax, depreciation, amortisation, impairment and exploration expense (EBITDAX1) decreased to $1.67 million, compared
to a loss of $8.45 million in the prior year.
1 A reconciliation of EBITDAX is shown below.
Statutory loss after tax
Add/(less):
Net interest
Income tax
Depreciation and amortisation
Impairment of assets
EBITDA
Exploration expense
EBITDAX
2015
$ million
(27.73)
2014
$ million
(10.86)
3.60
—
2.71
12.09
(9.33)
7.66
(1.67)
0.73
(4.11)
1.13
(13.11)
4.66
(8.45)
The resulting EBITDAX loss of $1.67 million reflects a period of substantial transition in Central’s operations. The operating and depreciation
costs for Palm Valley reflect its first full year of operations, however, gas sales were in a period of anticipated ramp‐up and did not achieve
full contracted volumes until May 2015. In addition, Dingo operating and depreciation costs commenced from 1 April 2015 even though
Take‐or‐Pay revenue of $2.2 million that was generated to 30 June 2015 was not recognised during the reporting period. This Take‐or‐Pay
revenue is payable in January 2016 and will be accounted for in the financial year ending 2016 (refer Note 1(e)(i)).
Cash
At 30 June 2015 consolidated cash and cash equivalents available totaled $3,516,139 (2014: $10,330,474), including $261,827 (30 June 2014:
$1,590,386) held in joint venture. Available to the Company at 30 June 2015 was $2.7 million in undrawn debt facilty.
Capital Expenditure
Capital expenditure of $20.85 million (2014: $46.1 million) relating largely to completion of the Dingo pipeline and gas processing facilities.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
7
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
Financial Review (continued)
Comparative 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.
2015
$ million
2014
$ million
2013
$ million
2012
$ million
2011
$ million
Financial Data
Operating revenue
Exploration expenditure
Loss after income tax
Equity issued during year
Property, plant and equipment
Borrowings
Net Assets (Total Equity)
Net Working Capital
Operating Data
Gas Sales (GJ)
Oil Sales (barrels)
10.31
7.66
27.73
5.56
58.58
(47.46)
23.15
(4.41)
3.72
4.66
10.86
24.97
46.27
(23.76)
43.07
2.78
1,194,153
53,925
267,328
17,489
No. of employees at 30 June
58
51
—
6.98
9.28
7.56
1.28
—
24.65
4.93
—
—
26
—
18.72
26.36
23.60
1.78
—
24.20
10.64
—
—
17
—
31.34
36.64
5.90
0.83
—
25.90
12.14
—
—
19
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.
Over the past year, Central has substantially increased operating activities, notably in the production and sale of oil and gas. Central’s
operations have a significantly different risk profile compared to exploration. Central’s key operating risks include changes in operating costs,
changes in capital maintenance and replacement costs, plant availability and sub‐surface extraction. In addition, Central is exposed to
changes in $A commodity prices with respect to crude oil sales which are benchmarked against $US international markets. The majority of
Central’s revenues, however, are generated by gas sales which effectively mitigates $A commodity price risk through the use of long‐term,
$A fixed price gas sales agreements with credit worthy customers.
8
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
Financial Review (continued)
Business Strategy
Whilst Central has historically been a pure oil and gas exploration company, over the past 2 years Central has developed and successfully
pursued a strategy to gain critical mass in conventional gas production, including contracted gas sales and uncontracted gas reserves. This
strategy first crystalised through the acquisition of the Palm Valley and Dingo gas fields from Magellan in April 2014, marking Central’s entry
into commercial gas production. Over the financial year ending 30 June 2015, Central ramped up its contracted gas sales as scheduled for
the Palm Valley gas field and completed development of the Dingo gas field in 1 April 2015 on time and under budget.
Central’s business strategy was bolstered significantly on 1 September 2015 when Central completed the acquisition of 50 percent of the
Mereenie oil and gas field from Santos and became Operator for the Joint Venture. The past 18 months have been a period of business
strategy implementation making Central a substantive domestic gas producer, with approximately 11 TJ/d contracted sales equity accounted
and growing uncontracted gas reserves from proven fields.
With Mereenie, Palm Valley and Dingo fields under our common Operatorship, Central is now in a unique position to participate (and actively
support) the North East Gas Interconnect (NEGI) pipeline connecting the Northern Territory to the eastern seaboard. This project is driven
by clear fundamentals of a domestic gas shortfall on the East Coast and underexplored on‐shore gas potential in the Northern Territory. In
linking supply and demand, Central’s sound business strategy of acquiring gas assets and uncontracted reserves in advance of the NEGI
pipeline has positioned it to be a direct and substantive beneficiary.
Whilst the implementation of Central’s Business Strategy has been relatively swift, the aggressive and sustained downturn in oil prices has
served to justify our transition into gas starting 2 years ago. The acquisition of Palm Valley, Dingo and now Mereenie have all been based on
existing gas contracts which are structured as long‐term fixed price, CPI escalation. This provides a solid revenue stream going forward to
cover Central’s operating activities and debt financing arrangements secured on long term gas contracts that are not affected by oil price or
currency movements and therefore largely unaffected by turmoil in international oil or LNG markets.
Creating a market for our gas should materially re‐rate our significant under explored permits throughout the Amadeus, Southern Georgina,
Pedirka and Wiso Basins in Central Australia. Going forward, our portfolio now allows Central to generate critical free cash flow after debt
service which can be applied towards high growth and value adding activities, notably initially targeting growing high value conventional gas
reserves throughout our various exploration permits.
Granted Petroleum Licences and Application Interests
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
9
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
Operations and Activities
Palm Valley Gas Field (OL3)
Northern Territory
(CTP — 100% Interest)
Background
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.
Performance
Gas production for the period 1 July 2014 to 30 June 2015 was 1,247,593 GJ (1.2 PJ).
Palm Valley field also pre‐delivered 150 TJ of gas into the Dingo contract while purchaser worked to effect upgrades to their facilities.
Gas sales are per nominations received from the purchaser. Palm Valley currently delivers approximately 5 TJ/day into the Northern Territory
domestic market.
1 Mereenie Oil converted at 5.816 GJ/BOE
2 Central had no ongoing production prior to April 2014
A review of the field performance was conducted, leading to an upgrade in outlook for gas production. Internationally recognised petroleum
consultants Netherland, Sewell & Associates, Inc. (NSAI) estimated petroleum reserves and contingent resources as announced to the ASX
on 21 July 2015.
Two exploration targets within the licence area have benefited from review of existing and acquisition of additional geological and
geophysical data.
The Palm Valley Deep prospect has been firmed up with a drilling location selected. The objective is a test of the deeper Arumbera Sandstone
which is an established gas bearing reservoir in the Dingo gas field some 100 km eastwards. The target has a similar area to the producing
gas pool in the Pacoota Sandstone. The company sought regulatory permission from the Northern Territory Department of Mines and Energy
(DME) and Central Land Council (CLC) clearance to drill Palm Valley‐12.
The Palm Valley West lead has been updated with additional data collected from surface mapping. The initial results are positive, and the
company intends to conduct additional surveying.
10
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
Dingo Gas Field (L7) and Dingo Pipeline (PL30)
Northern Territory
(CTP — 100% Interest)
Background
During the June 2014 Quarter the Northern Territory Government granted the Dingo Petroleum Production Licence (L7) to Central. The
production licence was converted from the retention licence (RL2).
Subsequent to 30 June 2014, the Dingo Pipeline Licence (PL30) was awarded by the Northern Territory Department of Mines and Energy.
The Dingo Gas Field Development was funded under a $30 million tranche of the loan facility agreement with Macquarie Bank and comprised
construction of wellhead facilities, gathering pipelines, gas conditioning facilities, a 50 km gas pipeline to Brewer Estate in Alice Springs and
custody transfer metering facilities designed to service a gas sale contract with Power and Water Corporation of the Northern Territory
providing fuel to Owen Springs Power Station.
Performance
Construction of the pipeline was completed using innovative construction practices to add efficiency and reduce environmental footprint.
Landowners, Traditional Owners and Environmentalists have reacted favorably to the project.
The strategic pipeline was a major milestone and signified the start of the Company being a significant player in the Northern Territory gas
market. Central looks forward to playing an important role in inter‐connecting Central Australia to the Eastern seaboard gas network via the
North East Gas Interconnector (NEGI).
Dingo Gas processing plant during final commissioning early 2015.
Central conducted a review of geological and engineering data, leading to a belief in upside potential of the field. Internationally recognised
petroleum consultants Netherland, Sewell & Associates, Inc. (NSAI) estimated petroleum reserves and supported an increase in contingent
resources as announced to the ASX on 21 July 2015.
Several structural leads were identified in the area immediately surrounding Dingo gas field, within EP 82 which is operated by Santos. These
could provide interesting incremental opportunities to Central’s 100 percent Dingo infrastructure. Further seismic is required to progress the
targets to drillable status.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
11
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
Mereenie Oil and Gas Field (OL4 and OL5)
Northern Territory
(CTP — 50% Interest, Santos — 50% Interest)
On 4 June 2015, CTP announced its acquisition of a 50 percent interest in the Mereenie oil and gas field under a farmout agreement with
Santos.
Background
The Mereenie oil and gas field was discovered in 1963 by the exploration well, Mereenie‐1, which
was drilled on the crest of a large surface expressed anticline, with subsurface field area up to
~25,000 acres, or 100 km2. Hydrocarbon‐saturated reservoirs of variable quality within the Stairway
and Pacoota formations below the regional Stokes Siltstone seal. In most gas bearing reservoirs
there is a gas saturated oil rim. The gross hydrocarbon column in the field is approximately
760 metres.
Gas production and export via pipeline to Darwin commenced in 1984, with flow rates increasing to
a peak of ~53 TJ/d in 2005 before declining for contractual reasons. During the seven years from
1990 a further 20 “oil” wells were drilled, adding to gas production capacity, followed by 6 dedicated
gas wells during 1999–2004, and 4 oil wells since 2007. Hydraulic fracture stimulation was
successfully applied during the 1990s, but only eight wells were stimulated since then.
Following expiry of the long term gas contract in 2009, the operator undertook studies and then
acted in 2010 with the expansion of gas re‐injection to enhance oil recovery. As of 2014 the field
was producing up to 1,000 bopd (oil, condensate) from 23 wells, selling ~5 TJ/d gas (1.8 PJ pa) and
reinjecting the balance into the oil reservoirs.
Gross production of 30 years to date is approximately 17 MMbbl oil, 258 PJ sales gas, and 1 MMbbl condensate.
With historical gas production of over 50 TJ/d, Mereenie can become a primary supplier of gas to the Eastern Seaboard via NEGI.
Performance
In a transformational acquisition CTP assumed Operatorship of historic Mereenie Field on 1 September 2015. CTP managed over 20 work
streams to successfully accomplish the handover.
Key activities in the assumption of operatorship included:
Job offers and acceptance by 15 current field employees.
Contracting all services to operate the field.
Re‐structure of Central Operations team to gain efficiency across all fields; Palm Valley, Dingo and Mereenie.
Securing of additional gas contracts.
Development of robust computer models to support reserve and production upgrades to underpin the NEGI pipeline.
12
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
ATP909, ATP911 and ATP912
Southern Georgina Basin, Queensland
(CTP — 90% Interest, Total — 10% interest)
Farmout
During Stage 1 the Joint Venture acquired and interpreted 974 km 2D seismic, which enabled the selection of drilling locations. Two
exploration wells were drilled in second half of 2014.
Should Total continue and fulfil its funding obligations for Stages 2 and 3, it will earn equity in increments to a total of 68 percent in the
permits.
Central is operating the farmout areas for the first four years and after completion of Stage 3 Total will assume operatorship for 90 percent
of the area. Central will retain operatorship of the upstream activities on the remaining 10 percent of the area.
Drilling
Whiteley-1 Well
Drilling commenced on 20 July 2014 at the Whiteley‐1 unconventional gas exploration well in
ATP 912.
Whiteley‐1 was the first of a programme of unconventional gas exploration wells operated by
Central and drilled using Enerdrill Rig 2. The planned depth was 1,920 metres.
The well was drilled to around 1,150 metres where severe drilling losses caused a suspension of
drilling operations, pending the arrival of specialty equipment. The extent of fluids losses indicates
a porous and perhaps fractured reservoir, which is yet to be fully logged for evaluation.
Gaudi-1 Well
Gaudi‐1 spudded on 14 September 2014 in ATP 909, reached total depth of 2,430 metres, and the
rig was released on 12 November 2015. Continuous coring operations retrieved 282 metres of core
from which desorption samples were taken. A comprehensive suite of wireline logs were acquired
in the well. Elevated gas readings recorded during drilling were confirmed by gas that desorbed
from the core over time.
Evaluation
Data collected during Stage 1 includes laboratory analyses of core from Gaudi‐1 and of core taken in offset wells, and is substantially
complete. Analytical results have been integrated with interpreted logs and revised depth maps. This allows regional trend mapping using
geologic attributes porosity, thermal maturity, and total organic carbon (TOC) etc. These provide insight into the unconventional LAC shale
gas play, as well as new plays which have been revealed in the middle Cambrian succession.
The exploration targets in the joint venture’s permits are now expanded to include:
1.
Shale and tight gas reservoirs within the Lower Arthur Creek Fm, as targeted by Gaudi‐1; and
2. A potential structurally controlled Hydrothermal Dolomite (HTD) play. Global analogues for this type of play are characterised by
the highly localised creation of porosity in otherwise tight carbonates by the movement of hot geothermal fluids through the
succession, upwards along faults. The types of mineralisation observed in the Gaudi‐1 and nearby mineral well cores, the lost
circulation in Whiteley‐1, and anomalies observed on seismic all provide evidence for the possible presence of this play within the
joint venture’s permits.
The joint venture is considering various options to progress evaluation of these plays, and seeks additional play types and targets which may
exist in these large permits.
Future drilling plans
Whiteley-1 well
The joint venture is encouraged by the evaluation detailed above, and believes Whiteley‐1 may be ideally located, as estimated from various
geologic parameters. An operational plan has been prepared to enable re‐entry of Whiteley‐1 so we may test the tight gas play, and several
secondary targets. The primary objectives are targeted to be fully cored and sampled for gas desorption and reservoir properties, in addition
to an extensive logging program.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
13
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
Southern Amadeus Basin
Northern Territory
Various Permits, Retention Licences and Application Areas
(See Table on Page 89)
Santos Farmout
Under a three stage farmout agreement, Santos funded exploration in Stage 1 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 percent of the area totaling
nearly 80,000 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 Stage 1 seismic acquisition program acquired 1,587 km 2D seismic over 7 permits in the Southern Amadeus area, an additional 323 km
in the North Mereenie Block (EP 115NMB), and the drilling of an exploration well, Mt Kitty‐1. Stage 1 activities concluded in June 2014.
The Mt Kitty‐1 well was re‐entered on 23 August 2014, and a comprehensive logging program was completed which confirmed that gas flows
reported did emanate from fractures in granitic basement. The well was suspended for possible later re‐entry. Isotope analysis of gas samples
confirmed the validity of previously announced helium contents up to 9 percent. This “fractured basement” discovery has opened up an
additional play type which forms a valid objective in future wells.
Central and Santos concurred that the prospectivity of the Southern Amadeus was confirmed by the results of Mt Kitty and the 1,587 km of
2D seismic acquired during Stage 1 of the farmout. As a result, Santos elected in July 2014 to proceed to Stage 2 of an amended Southern
Amadeus Joint Venture with Central, where 1,300 km 2D seismic will be acquired across areas of highest prospectivity, earning Santos a
40 percent participating interest in permits listed in the table below (the “Southern Amadeus Joint Venture”).
The joint venture’s exploration endeavours in this and surrounding permits will focus on maturing large sub‐salt leads to drillable status by
acquiring further seismic in Stage 2. The primary reservoir objective is the Heavitree Quartzite. Secondary reservoir objectives in the
Neoproterozoic succession include fractured basement, the Pioneer Sst which is gas productive in the sub‐commercial Ooraminna field, and
the Areyonga Fm.
SOUTHERN
AMADEUS AREA
EP82
EP105
EP106
EP107
EP112
EP(A)147
TOTAL SANTOS PARTICIPATING INTEREST
AFTER COMPLETION OF STAGE 1
25%
25%
25%
25%
25%
25%
TOTAL SANTOS PARTICIPATING INTEREST
AFTER COMPLETION OF STAGE 2
40% (i.e. additional 15% earned)
40% (i.e. additional 15% earned)
40% (i.e. additional 15% earned)
40% (i.e. additional 15% earned)
40% (i.e. additional 15% earned)
40% (i.e. additional 15% earned)
EP 125 – Northern Territory
(CTP — 30% Interest, Santos [Operator] — 70% interest)
Mt Kitty-1 Exploration Well
The Mt Kitty “fractured basement” discovery has opened up an additional play type which forms a valid objective in future wells, in addition
to the large sub‐salt leads present across the wider area.
Uncertainties remain as to the size of the resource discovered in the Mt Kitty‐1 exploration well. Poorly constrained input parameters to
resource assessment include reservoir pressure which is an indication of column height, porosity and extent or connectivity of the fracture
system, as well as the source and exact gas composition. The available options to evaluate this large structure are to re‐enter Mt Kitty‐1 for
testing, or drill an oriented sidetrack to maximise intersection with observed fracturing, or drill additional wells on the structure.
Helium detected in the gas stream sells around $100/mcf (or nearly twenty times more valuable than natural gas), so the 9 percent helium
detected in the gas stream is significantly more valuable than methane. The gas‐in‐place estimates and potential well performance are
significant in determining the potential commerciality of the resource. 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.
14
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
Surprise Oil Field (L6)
Northern Territory
(CTP — 100% Interest)
Background
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 was
completed early in the financial year.
Performance
The Surprise West well produced approximately 77,232 barrels of oil since commencing production in March 2014 to 30 June 2015 of which
54,374 barrels were produced during the period 1 July 2014 to 30 June 2015.
The Surprise West well was a valuable cash‐flow contribution to the Company. Currently the well is shut in due to low oil prices and to obtain
long term pressure data.
Exploration Application Areas, Northern Territory
Amadeus, Pedirka and Wiso Basins — Various Areas (see Table on Page 89)
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.
In the western Amadeus Basin a gravity survey was conducted by Geoscience Australia and Northern Territory Geologic Survey, in which
Central participated and sponsored a higher level of detailed surveying. The additional data has clearly delineated structural trends which
are anticipated to be prospective, and supports modeling to identify and prioritise areas of prospective sediments which are structurally
high. This will greatly assist efficient layout of seismic acquisition to define drillable targets.
Western Amadeus Basin, Residual
gravity, licenced and application
areas.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
15
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
Exploration Application Areas, Northern Territory (continued)
In the Wiso Basin a gravity survey was conducted by Geoscience Australia and Northern Territory Geologic Survey in 2013, which has provided
Central with improved detailed of structural trends. Interpretation in conjunction with magnetics data (see image below) provides an
excellent tool for planning of seismic acquisition.
Wiso Basin, Residual gravity, application areas.
Reserves Information
Reserves and Resource Volumes for Gas (Units: PJ)1
Palm Valley3
Dingo3
Mereenie2
Total
1P
18.4
10.8
35.6
64.8
2P
24.6
34.6
122.9
182.1
3P
—
—
152.3
152.3
1C
—
—
46.0
46.0
2C
—
—
144.0
144.0
3C
—
—
261.0
261.0
1Reserves/Resources are 100% Gross (Field Level)
2Mereenie Reserves are from YE2014 Santos VOLTS Database
3Palm Valley & Dingo Reserves are from NSAI Report 13964 dated 30 June 2015
SIGNIFICANT CHANGES IN THE STATE OF AFFAIRS
Significant changes in the state of affairs of the group during the financial year were as follows.
Contributed equity increased by $5,562,142 (from $155,223,040 to $160,785,182) as the result of a share placement. 20,000,000 fully paid
ordinary shares were issued on 2 October 2014 at an issue price of 30 cents per share. Details of the changes in contributed equity are
disclosed in Note 18(a) to the Financial Statements.
16
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
EVENTS SINCE THE END OF THE FINANCIAL YEAR
Acquisition of a Fifty Percent (50%) Interest in the Mereenie Oil and Gas Field
On 1 September 2015 the consolidated entity acquired a 50 percent interest in the Mereenie oil and gas field in the Amadeus Basin, Northern
Territory from the Santos group. The Company assumed operatorship of the field effective from that date. A new joint venture will be
established.
The financial effects of this transaction have not been recognised at 30 June 2015 and the acquisition will be included in consolidated results
from 1 September 2015.
Purchase Consideration
Cash paid
Deferred consideration
Free carry of Santos’ share of field appraisal and development
Total purchase consideration
$
35,000,000
10,000,000
5,000,000
50,000,000
As part of the transaction the parties have agreed to a range of matters relating to other Southern Amadeus Basin exploration arrangements
between the parties. The fair values of the assets and liabilities as at the date of acquisition are yet to be determined.
Contingent Consideration
Potential consideration as indicated above is payable if a final investment decision is made on the North East Gas Interconnector (NEGI)
and the Mereenie Joint Venture participants (or their related parties) enter into a gas transportation agreement with the NEGI project
owner within 3 years of the execution date.
The potential consideration comprises a $15 million payment and $55–75 million of sole funding work to prove up 15 PJ per annum over
10 years in excess of contracted gas for the purposes of transportation via the NEGI. A bullet payment of 50 percent of the remaining
balance of the target of $65 million is payable if the required NEGI works are not completed within 3 years of the pre‐conditions being
satisfied.
The potential undiscounted amount of all future payments that the consolidated entity could be required to make under this
arrangement is between $0 and $47,500,000.
Debt Facility
As part of the Mereenie acquisition, the Macquarie debt facility has been expanded to include a new Facility “D” of $40 million taking
the total facility limit to $90 million with a final maturity date of 30 September 2020.
The existing repayment schedule has been replaced with a new repayment schedule. Commencing 31 December 2015 the principal
repayment (excluding interest accruing under the facility) is a set amount of $1 million per quarter payable at the end of each calendar
quarter with the balance of the facility due on the final maturity date.
Financial covenants under the revised facility:
• Current Ratio is at least 1:1
• Proved Developed Producing (PDP) Reserves Cover Ratio is greater than 1.3:1
• Trade creditors ageing over 90 days past the due date must not exceed $5 million.
Legal Matter
Central Petroleum Limited has been allegedly served with litigation filed in the District Court of Harris County Texas, located in Houston,
Texas, in respect of a farm‐in deal negotiated between the Perth office of Total and Central Petroleum when it was headquartered in Perth.
Central Petroleum is disputing the Court’s jurisdiction. Separately, internal investigations have concluded that there is no factual basis for
the alleged claim and the consolidated entity accordingly denies any liability. The action will be vigorously defended.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
17
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
INFORMATION ON DIRECTORS
Robert Hubbard FCA
Independent Non‐Executive Director
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. He is also a
non‐executive director of ASX listed Primary Health Care Limited. Within the last three years, he has not been a Director of any other listed
public company.
Andrew P Whittle BSc (Hons)
Independent Non‐Executive Chairman
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 was a founding
Director, 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 also stepped down as a non‐executive Director of ASX listed Bass Strait Oil Ltd during the year. Within the last three
years, he has not been a Director of any other listed public company.
Richard I Cottee BA, LLB (Hons)
Managing Director and Chief Executive Officer
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 was until April of this year 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.
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 $300 million in annual sales to $2.2 billion 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.
18
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
INFORMATION ON DIRECTORS (continued)
John Thomas (Tom) Wilson BSc (Zoology), MSc (Geology)
Independent 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.
Prof. Peter S Moore BSc (Hons 1), MBA, PhD
Independent Non‐Executive Director
Prof. Peter S Moore has over thirty years of experience in the oil and gas business. His career includes roles with the Geological Survey of
Western Australia, Delhi Petroleum Pty Ltd, the exploration operator of the Cooper Basin consortium in South Australia and Queensland at
the time, Esso Australia Ltd, Exxon Exploration Company in Houston and from 1998 until his retirement in 2013, with Woodside Energy Ltd.
At Woodside, Peter held various roles including most recently as Executive Vice President Exploration. In this capacity he was a member of
Woodside’s Executive Committee and Opportunities Management Committee, a leader of its Crisis Management Team and Head of the
Geoscience function across the company. He was also a Director of a number of Woodside’s subsidiary companies.
Prof. Moore is Chair of the Curtin Graduate School of Business Advisory Board, an Executive Director of ESWA (Earth Sciences WA), a Non‐
Executive Director of Carnarvon Petroleum Limited, and a Member of the Elsevier’s Oil & Gas Advisory Board. Within the last three years, he
has not been a Director of any other listed public company.
COMPANY SECRETARIES
Daniel C M White LLB, BCom, LLM
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 FAIM, GAICD
Mr Morfea has over 35 years of experience in the resource industry having held key financial positions with both Australian and international
based companies. He was previously the Chief Financial Officer of Magellan Petroleum Australia Pty Ltd, a wholly owned subsidiary of Denver
based Magellan Petroleum Corporation. Prior to Magellan Mr Morfea worked for Santos Limited and Thiess Dampier Mitsui Coal Pty Ltd.
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:
Robert Hubbard
Andrew Whittle
Richard Cottee
Wrixon Gasteen
J. Thomas Wilson
Peter Moore
William Dunmore
Michael Herrington
Full Meeting of
Directors
Audit
Committee
Remuneration
Committee
Nominations
Committee
Eligible
7
7
7
7
7
7
3
3
Attended
7
7
7
7
4
7
2
3
Eligible
2
2
—
2
—
—
—
—
Attended
2
2
—
2
—
—
—
—
Eligible
3
3
—
—
—
3
—
—
Attended
3
3
—
—
—
3
—
—
Eligible
—
1
1
—
—
1
—
—
Attended
—
1
1
—
—
1
—
—
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
19
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
REALISED REMUNERATION OF DIRECTORS AND KEY MANAGEMENT
PERSONNEL FOR THE 2015 YEAR
The Directors consider the remuneration information contained within the tables presented in the statutory remuneration report (pages 22
to 34) may give a distorted view of the true remuneration realised by the Directors and key management personnel for the 2015 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 Dunmore2
Wrixon Gasteen
Robert Hubbard
J. Thomas Wilson
Peter Moore
Salary / fees
$
102,667
27,083
67,500
72,000
58,500
72,000
Non-monetary
benefits1
$
10,799
—
11,999
—
—
—
Superannuation
contributions
$
9,753
—
—
6,840
—
6,840
Amount
$
123,219
27,083
79,499
78,840
58,500
78,840
Sub‐total
399,750
22,798
23,433
445,981
Executive Directors
& Key Management
Personnel
Richard Cottee3
Michael Herrington2
Daniel White
Bruce Elsholz4
Leon Devaney
Michael Bucknill
Robbert Willink
Salary / fees
$
581,784
512,259
411,575
160,171
358,095
337,352
340,000
Non-monetary
benefits1
$
20,319
12,494
1,826
1,694
1,694
1,694
—
Superannuation
contributions
$
5,985
36,572
30,000
22,556
27,780
32,048
32,300
Amount
$
608,088
561,325
443,401
184,421
387,569
371,094
372,300
Sub‐total
2,701,236
39,721
187,241
2,928,198
Total Remuneration
3,100,986
62,519
210,674
3,374,179
Percentage
of TRP
%
Value of LTI
Grant that
Vested
$
100%
100%
100%
100%
100%
100%
100%
—
—
—
—
—
—
—
Percentage
of TRP
%
Value of LTI
Grant that
Vested
$
Actual Total
Remuneration
Package (TRP)
$
123,219
27,083
79,499
78,840
58,500
78,840
445,981
Actual Total
Remuneration
Package (TRP)
$
608,088
561,325
443,401
184,421
387,569
373,094
374,700
—
—
—
—
—
2,000
2,400
4,400
2,932,598
4,400
3,378,579
100%
100%
100%
100%
100%
99%
99%
100%
100%
1.Fringe benefits
2 Retired as Director 26 November 2014
3 Mr Cottee’s services were provided by Freestone Energy Partners (FEP) up to 29 June 2015 when he became a full time employee. Mr Cottee has a 50% beneficial equity interest.
4 Resigned 30 November 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 56 employees at 30 June 2015 (51 at 30 June 2014).
20
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NON-AUDIT SERVICES
During the year the Company engaged the auditor, PricewaterhouseCoopers (PwC) on assignments additional to their statutory audit duties
where the auditor’s expertise and experience with the Company and/or the Consolidated Entity was important.
Details of amounts paid or payable to the auditor (PwC) for non‐audit services provided during the year are set out below.
The board of Directors is satisfied that the provision of the non‐audit services is compatible with the general standard of independence for
auditors imposed by the Corporations Act 2001. The Directors are satisfied that the provision of non‐audit services by the auditor, as set out
below, did not compromise the auditor independence requirements of the Corporations Act 2001 and did not compromise the general
principles relating to auditor independence in accordance with APES 110 Code of Ethics for Professional Accountants set by the Accounting
Professional and Ethical Standards Board.
PwC Australian firm:
(i) Taxation services
Income Tax compliance
Excise consulting
Other tax related services
(ii) Other services
Corporate advisory – due diligence
Remuneration benchmarking
Other employee related services
Total remuneration for non‐audit services
AUDITOR’S INDEPENDENCE
CONSOLIDATED
2015
$
8,500
48,957
68,354
125,811
22,000
—
6,698
28,698
154,509
2014
$
16,311
—
65,955
82,266
181,607
10,000
—
191,607
273,873
A copy of the Auditor’s Independence Declaration as required under section 307C of the Corporations Act 2001 is set out on page 35.
STAFF AND MANAGEMENT
The Directors wish to acknowledge the contributions made by the Company’s staff and management. The skills and dedication of all of
Central’s personnel both in the field and at Head Office are greatly appreciated. Of special note are the contributions made to the Company’s
operations by Mr Robert Liddle and the other traditional owners who are part of the Central work force.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
21
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
REMUNERATION REPORT (AUDITED)
This remuneration report for the year ended 30 June 2015 outlines the remuneration arrangements of the Group in accordance with the
requirements of the Corporations Act 2001 (Cth), as amended (the Act). This information has been audited as required by section 308(3C)
of the Act.
The remuneration report is presented under the following sections:
A
B
C
D
E
F
G
H
I
Directors and Key Management Personnel (KMP)
Remuneration Overview
Remuneration Policy
Remuneration Consultants
Long Term Incentive Plan (LTIP)
Short Term Incentive Plan (STIP)
Remuneration Details
Executive Service Agreements
Non‐Executive Director Fee Arrangements
A. Directors and Key Management Personnel
The Directors and key management personnel of the Consolidated Entity during the year and up to signing date of the annual report were:
Directors
Robert Hubbard
Andrew Whittle
Richard Cottee
Wrixon Gasteen
J. Thomas Wilson
Peter Moore
Michael Herrington
William Dunmore
Non‐Executive Chairman
Non –Executive Director
Managing Director and Chief Executive Officer
Non‐Executive Director
Non‐Executive Director
Non‐Executive Director
Executive Director and Chief Operating Officer
Non‐Executive Director
Other Key Management Personnel
Leon Devaney
Michael Herrington
Daniel White
Michael Bucknill
Robert Willink
Bruce Elsholz
Chief Financial Officer
Chief Operating Officer
Group General Counsel and Company Secretary
General Manager Exploration
Exploration Advisor
Chief Financial Officer and Company Secretary
B. Remuneration Overview
Retired as Director, effective 26 November 2014
Retired, effective 26 November 2014
Appointed, effective 31 October 2014
Resigned, effective 31 October 2014
Central Petroleum’s remuneration strategy is designed to attract, motivate and retain high performing individuals and is linked to the Group’s
objectives to build long‐term shareholder value. In doing so, Central adopts a pay for performance culture which is balanced by a fair and
equitable approach to the retention and motivation of its team. The remuneration strategy incorporates the following metrics:
a) Measuring Central’s achievement of its targets and performance against its peers.
b) Peer company comparative indicators such as market capitalisation, size, complexity of operations and market developments.
c) Adjusting to remuneration best practice.
d) Market movements and its impact on the alignment of internal relativities.
e)
Linking internal strategies for the achievement of improved shareholder value.
22
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
B. Remuneration Overview (continued)
In the previous remuneration review cycle during 2014 the Board engaged PricewaterhouseCoopers to provide guidance on current industry
practice for remunerating senior executives, and RMBN Pty Ltd to carry out a review of the proposed STIP and LTIP plans. The implementation
of these Plans met key fundamentals that focused on creating strong linkages between shareholder value as measured by shareholder returns
(Absolute and Relative total shareholder returns). A detail overview of the LTIP and STIP plans that were implemented for the period starting
1 July 2014 can be found at section D and E of this report.
Australia is in the midst of a significant contraction in the resource sector as commodity prices remain at multi‐year lows and the outlook for
most commodity markets remains clouded due to concerns over global growth. Since October 2014, the energy sector has been under
increasing financial pressure, largely due to the collapse in oil prices as well as gas pricing linked to oil. This has had a profound impact on all
energy sector participants. In respect of this market dynamic, the CEO positioned the Company’s focus on restoring value for shareholders
by reducing costs, driving operational efficiency and prudently managing capital and targeting non‐oil linked gas pricing.
With the significant contraction in the resource sector specifically with the downturn in the global oil prices and corresponding loss of value
in the market, Central Petroleum undertook the suspension of its 2014 pay reviews and STIP payments:
Suspended Pay
No pay rises were awarded except where appropriate on account of a change in position or other extenuating
circumstance
Suspended STIP
The Company’s Short Term Incentive Plan was scheduled for payment in the fourth quarter of fiscal year 2015,
however, the Board with the full support of the CEO exercised its discretion to reduce and suspend its payment
to the fourth quarter of calendar year 2015.
Nil LTIP VESTING
There were no awards that vested under the new Long Term Incentive Plan with it coming into its second year
of implementation.
C. Remuneration Policy
The remuneration policy of the Company is to pay its Directors and executives amounts in line with employment market conditions relevant
to the oil and gas exploration industry. Accordingly, the Company has revamped 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 effective from 1 July 2014.
D. Remuneration Consultants
For each annual remuneration review cycle, the Remuneration Committee considers whether to appoint a remuneration consultant and, if
so, their scope of work. In this period the Remuneration Committee did not engage a remuneration consultant.
The performance of the Company depends upon the quality of its Directors and executives and the Company strives to attract, motivate and
retain highly qualified and skilled management. Salaries and Directors fees are reviewed at least annually to ensure they remain competitive
with the market.
For periods up to and ending on 30 June 2015 the remuneration of Directors and executives consisted of the following key elements:
Non‐Executive Directors:
1.
Fees including statutory superannuation; and
2. No further participation in short or long term incentive schemes. Whilst some of the current non‐executive Directors benefit from
options issued in accordance with shareholder approval in 2012 no further issues have been made and it is not intended that non‐
executive Directors will participate in either the LTIP or STIP in the future.
Executives including executive Directors:
1. Annual salary and non‐monetary benefits including statutory superannuation;
2. Participation in a Short Term Incentive Plan;
3. Participation in an Long Term Incentive Plan (Performance Rights scheme); and
4. There is no guaranteed base pay increases included in any executive’s contract.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
23
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
E. Long Term Incentive Plan (LTIP)
In its 2014 annual report CTP announced that from 1 July 2014 it would change its remuneration practices and in particular the structure of
its short term incentive plan and LTIP in line with market conditions relevant to the oil and gas exploration industry.
The LTIP will be a major component of executive incentives and in developing the LTIP the board of CTP has focused on creating strong
linkages between shareholder value as measured by shareholder returns and executive remuneration. Consequently vesting conditions have
been divided equally between relative shareholder return and absolute shareholder return. In doing this the board have identified that it is
not sufficient for CTP to perform above its peer group for executives to receive their maximum entitlement to share rights but also to achieve
levels of absolute share price growth that would be considered as superior returns. For example for the absolute share price vesting condition
to be met the CTP share price must increase by at least 25 percent per annum for three years, compound growth of 95 percent.
Key terms and vesting conditions
On 26 November 2014 shareholders approved the Company to implement a share based LTIP to incentivise eligible employees (Non‐
Executive Directors are not eligible to participate in the LTIP). The delivery instrument is performance rights, effective for years commencing
1 July 2014 onwards.
The maximum number of performance rights vested in any year is determined by measuring CTP’s share price performance over that year
compared to a peer group of companies (relative measure) and compared to its absolute share price movement over a 3 year cycle.
The following table details the Vesting Percentage (The percentage of Share Rights which will vest as determined by the Performance
Conditions):
HURDLE
DEFINITION
Absolute TSR1 growth
(50% weighting)
Company's Absolute TSR calculated as at Vesting Date. This looks
to align Eligible Employee’s rewards to shareholder superior
returns
Relative TSR – E&P2
(50% weighting)
Company's TSR relative to a specific group of E&P companies
(determined by Board within its discretion) calculated as at
Vesting Date.
HURDLE BANDING
Company’s Absolute TSR
over 3 years
Below 10% pa
10% to <15% pa
15% to <20% pa
20% to <25% pa
25% pa plus
VESTING
PERCENTAGE
Share Rights Vesting
0%
25%
50%
75%
100%
Company’s Relative TSR
Share Rights Vesting
Below 51st percentile
51st percentile
52nd to 75th percentile
76th percentile and above
0%
50%
51% to 99%
100%
1 Total shareholder return (i.e. growth in share price plus dividends reinvested)
2 Exploration and Production
For the purposes of determining the maximum number of Unvested Share Rights available for vesting the Company will calculate the
Company’s Absolute TSR (Total Shareholder Return as measured by an independent Company chosen by the Board) and Relative TSR effective
as at the Vesting Date in accordance with the above table to determine the relative hurdle band and Vesting Percentage met. The Unvested
Share Rights for the applicable hurdle met for the Performance Period are then multiplied by the Vesting Percentage achieved for that hurdle
to determine the total number of Unvested Share Rights vested to become Share Rights on the Vesting Date which may then be exercised in
accordance with the ERP Rules.
Subject to the vesting of Unvested Share Rights on the Vesting Date, the Unvested Share Rights vest at the rate of one Share Right for one
Unvested Share Right.
The personal and corporate key performance indicators and other targets for the Managing Director and other employees are reviewed at
least annually to ensure they remain relevant and appropriate. These may be varied to ensure alignment of executive performance and
achievement consistent with the Company’s goals and objectives.
24
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
E. Long Term Incentive Plan (LTIP)
Employees must be employed by the Company at the end of the Performance Period in order for the Performance Rights to vest. The number
of shares that vest is a function of the employee’s base salary, their LTIP percentage, and the 20 Trading Days – daily volume weighted
average sale price of Company Shares sold on the ASX ending on the Trading Day prior to 30 June.
If the Company is subject to a Change of Control Event, all Unvested Share Rights will immediately vest at 100 percent to become Share
Rights, with all and any Performance Criteria being waived immediately.
Details of the LTIP Plan’s Key Terms can be viewed on the Company’s website at www.centralpetroleum.com.au.
This LTIP provides coverage for various levels of Eligible Employees which include:
a)
b)
c)
d)
e)
The Managing Director who is principally responsible for achievement of the CTP strategy may receive an LTIP Percentage up to
50 percent, subject to shareholder approval.
EMT (Executive Management Team) Eligible Employees are those in roles which influence and drive the strategic direction of the
Company’s business. EMT Eligible Employees receive an LTIP Percentage up to 30 percent;
Eligible Employees who are Senior Managers’ that are charged with one or more defined functions, departments or outcomes.
They are more likely to be involved in a balance of strategic and operational aspects of management. Some decision‐making at
this level would require approval from the Executive Management Team. These Eligible Employees receive an LTIP Percentage up
to 20 percent;
Eligible Employees who are not part of the EMT and are in roles which are focused on the key drivers of the operational parts of
the Company’s business. These Eligible Employees receive an LTIP Percentage up to 10 percent; and
All other Eligible Employees’ are integral to the success of the Company obtaining its goals and objectives may participate in
Central Petroleum $1,000.00 Exempt Plan.
Conditions of the Central Petroleum $1,000.00 Exempt Plan include:
1.
2.
Share Rights can only be dealt with the earlier of 3 years or on termination of employment; and
No performance conditions apply.
With the effective date of 1 July 2014 onwards, all eligible employees subscribed to the new Long Term Incentive Plan, and in doing so waived
their eligibility rights to participate in the incentive Options scheme.
F. Short Term Incentive Plan (STIP)
From 1 July 2014 a performance based plan comprising a matrix of Corporate, Departmental and Individual Key Performance Indicators
(KPI’s) for all eligible employees was implemented. The Company’s Board of Directors determine the maximum amount of KPI achievable in
any year (normally expressed as a percentage of base salary). Achieving the maximum is contingent upon all of the KPI’s in the matrix being
met at the 100 percent level. The KPI’s are reviewed at the beginning of each year and adjusted where necessary to reflect Central’s strategic
direction. Consistent with the Directors focus on appreciation in shareholder value as the major form of incentive, STIP payments were
limited to a maximum of 10 percent of base salary in 2014/15.
Key terms and conditions
The 2014/2015 STIP has been holistically designed to recognise and reward individual effort through connecting Individual KPI’s,
Departmental KPI’s and Corporate KPI’s. These groups of KPI’s are intrinsically linked and start by cascading from the Corporate KPI’s, to the
Departmental KPI’s and then onto Individual KPI’s. Individual KPI’s drive the success of achieving Departmental KPI’s which are in turn aimed
at effecting the desired outcome to be reached in the Corporate KPI’s.
It is the responsibility of the Board to set the strategic direction priorities and objectives of the Company. The existence of this STIP does not
amend or take away that responsibility and as such the results of the STIP form part of the Board’s deliberation in its decision on the bonus
recommendation to be awarded.
The Managing Director approves KPI’s after consultation with the Board. These KPI’s can change having regard to aligning employees with
the Company’s strategic direction, the practice in the marketplace and any other factors which the Board deems relevant. Neither the Board
nor the Company guarantee any payment from the STIP nor do they guarantee any performance level of the Company in future years. If
there is a change as a result of this, employees participating in the STIP will be notified.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
25
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
F. Short Term Incentive Plan (STIP)
KPI CATEGORY
Corporate KPI's
Safety & Environment
Departmental KPI's
Individual KPI's
PERCENT ALLOCATION OF STIP
Executive
All Other Employees
30%
10%
40%
20%
30%
10%
30%
30%
1.
2.
3.
Corporate KPI’s represent an overall 30 percent of the STIP, and Safety & Environment represents 10 percent of the STIP.
Departmental KPI’s represent a spread of 40 percent for the Executive and 30 percent for all other employees.
Individual KPI’s represent a spread of 20percent for the Executive and 30 percent for all other employees.
The 2014/2015 Plan Year STIP percentage allocation is a maximum of up to 10 percent of the employees Base Salary. The maximum is
contingent upon all of the KPI’s being met at 100 percent in the STIP. This will form the basis of the recommendation to the Board who will
decide the amount. This percentage will be annually reviewed by the Board through the Remuneration Committee.
At the Board’s discretion a combination of cash & Company securities, or cash or Company securities may be paid as the benefit in the
2014/2015 Plan Year STIP.
Corporate KPI’s included:
OBJECTIVE
WEIGHTING
100%
75%
50%
Supply gas from Dingo through pipeline
Complete 2014‐2015 SGJV work
program within JV approved AFE
amounts (in the aggregate)
Incremental sales contracts in
following year revenue
No Breach regarding Traditional Owner
cultural heritage
Training & Employment of Traditional
Owners
35%
20%
35%
5%
5%
By: 01/02/2015
By: 01/04/2015
By: 11/06/2015
At 90% or less of the
aggregate amount
Within 100% of the
aggregate amount
Under 110% of the
aggregate amount
$10 million
$7 million
$5 million
Zero
1 which has been remedied
Default
Two (2) trained
Two (2) employed
Two (2) trained
One (1) employed
Two (2) trained
OBJECTIVE
WEIGHTING
Safety: No Lost Time Injuries (LTI)
Environment: No breach regarding
reportable environmental incidents
5%
5%
100%
Zero
Zero
75%
1 of less than 2 days
50%
Default
The Departmental KPI’s vary from one department to the next, however, all are equally important to achieve in the pursuit of achieving
100 percent of the Corporate KPI’s which are re‐set annually.
Individual KPI’s are linked to the Departmental KPI’s and as such provides significant relevance to the role that the employee is employed for
in each department.
Participation in this STIP, or the provision of any Company security, does not form part of the participating employee's remuneration for the
purposes of determining payments in lieu of notice of termination of employment, severance payments, leave entitlements, or any other
compensation payable to a participating employee upon the termination of employment (unless the Board otherwise determines).
Incentive Option Schemes
On 9 April 2015, under the Company’s 2012 Share Option Plan for Directors and Employees, there were 5,288,843 unlisted options issued to
employees at various exercisable prices on or before 15 November 2017. The issue was for the performance period ending 30 June 2014.
26
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
G. Remuneration Details
Details of the remuneration of the Directors and the key management personnel of Central Petroleum Limited and the Consolidated Entity
are set out in the following tables. Details of realised remuneration appear on page 20.
Table 1: Remuneration of Directors and Key Management Personnel
SHORT-TERM
POST-EMPLOYMENT
LONG-TERM
BENEFITS
Salary / fees
$
Non-monetary
benefits1
$
Superannuation
contributions
$
Termination
Benefits
$
LSL
$
SHARE-BASED
PAYMENTS
(At Risk) Options
& Rights4
$
Value of
Options as
Proportion of
Remuneration
%
Total
$
Non-Executive Directors
Andrew Whittle
William Dunmore2
Wrixon Gasteen
Robert Hubbard
J. Thomas Wilson
Peter Moore
Sub‐total
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
102,667
101,666
27,083
94,476
67,500
75,000
72,000
40,265
58,500
16,250
72,000
16,042
10,799
11,707
—
—
11,999
13,008
—
—
—
—
—
—
399,750
343,699
22,798
24,715
9,753
9,404
—
—
—
—
6,840
3,724
—
—
6,840
1,484
23,433
14,612
Executive Directors and Other Key Management Personnel
Richard Cottee3
Michael Herrington2
Daniel White
Bruce Elsholz5
Leon Devaney
Michael Bucknill
Robbert Willink
Sub‐total
Total Remuneration
1 Represents fringe benefits tax.
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
561,976
580,005
506,102
587,995
397,106
432,155
120,520
303,726
361,706
311,241
330,641
321,663
349,810
340,236
20,319
—
12,494
11,707
1,826
—
1,694
—
1,694
—
1,694
—
—
—
5,985
22,945
36,572
33,068
30,000
26,693
22,556
27,689
27,780
29.180
32,048
27,651
32,300
29,116
2015
2,627,861
39,721
187,241
2014
2,877,021
11,707
196,341
2015
3,027,611
2014
3,220,720
62,519
36,421
210,674
210,954
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
12,398
7,536
9,214
6,298
10,972
10,014
2,212
7,520
6,830
3,837
4,260
2,560
4,553
2,816
99,124
118,392
—
—
110,138
131,547
—
—
—
—
—
209,262
249,939
222,343
241,169
27,083
94,476
189,637
219,555
78,840
43,989
58,500
16,250
78,840
17,526
655,243
632,965
1,887,313
1,887,313
2,487,991
2,497,799
91,152
118,392
(8,373)
3,733
(11,768)
2,622
(5,165)
2,576
(5,271)
2,000
(6,877)
2,400
655,534
757,460
431,531
472,595
135,214
341,557
392,845
346,834
363,372
353,874
379,786
374,568
50,439
1,941,011
4,846,273
40,581
2,019,036
5,144,687
50,439
40,581
2,150,273
5,501,516
2,268,975
5,777,652
45%
49%
0%
0%
58%
60%
0%
0%
0%
0%
0%
0%
32%
39%
75%
76%
14%
16%
0%
1%
0%
1%
0%
1%
0%
1%
0%
1%
40%
39%
39%
39%
2 Mr Dunmore and Mr Herrington retired as a directors 26 November 2014.
3 Freestone Energy Partners Pty Ltd (FEP) have provided the services of Richard Cottee on the basis of a secondment up to 29 June 2015. As such compensation was made to FEP in line with Richard Cottee’s
service agreement shown on page 33. Richard Cottee has a 50% beneficial equity interest in FEP.
4 The valuation date for options issued to FEP was 19 July 2012 and to directors was 29 November 2012. Negative amounts represent revisions to estimates and/or cancelled and forfeited options.
5 Mr Elsholz resigned from employment on 30 November 2014.
The fair values of options granted during 2015 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 fair values of
deferred share rights granted during 2015 were also independently valued. The values are calculated at the date of grant using a Black Scholes
valuation model with Monte Carlo simulations and a hypothetical comparator group to assess relative total shareholder return. The values
are allocated to each reporting period evenly over the period from grant date to vesting date.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
27
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
G. Remuneration Details (continued)
The values disclosed for 2015 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
1 Jul 14
11 Nov 15
9 Apr 15
9 Apr 15
9 Apr 15
15 Nov 17
15 Nov 17
15 Nov 17
$0.0200
$0.0033
$0.0062
$0.0067
$0.400
$0.475
$0.450
$0.400
PRICE OF
SHARES AT
GRANT DATE
$0.320
$0.125
$0.125
$0.125
ESTIMATED
VOLATILITY
45% to 65%
55% to 75%
55% to 75%
55% to 75%
RISK FREE
INTEREST
RATE
DIVIDEND
YIELD
2.54%
1.74%
1.74%
1.74%
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
10 Jul 13
15 Nov 15
28 Nov 13
15 Nov 17
$0.0471
$0.0450
$0.451
$0.475
PRICE OF
SHARES AT
GRANT DATE
$0.631
$0.320
ESTIMATED
VOLATILITY
60% to 90%
45% to 65%
RISK FREE
INTEREST
RATE
2.73%
2.69%
DIVIDEND
YIELD
Table 2: Share Based Compensation – Options Granted and Vested during the Year
NUMBER OF
OPTION
GRANTED
GRANT DATE
AVERAGE
FAIR VALUE AT
GRANT DATE
AVERAGE
EXERCISE
PRICE
PER OPTION EXPIRY DATE
NUMBER OF
OPTIONS
VESTED
PROPORTION
OF OPTIONS
VESTED
Non-Executive Directors
Andrew Whittle
William Dunmore1
Wrixon Gasteen
Robert Hubbard
J. Thomas Wilson
Peter Moore
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Executive Directors and Other Key Management
Richard Cottee
Michael Herrington1,3
Daniel White
Bruce Elsholz2
Leon Devaney
Michael Bucknill
Robbert Willink
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2015
2014
2015
2015
2014
—
—
—
1,800,000
450,000
733,334
370,500
570,000
504,000
560,000
100,000
330,000
—
120,000
330,000
—
—
—
—
28 Nov 13
9 Apr 15
10 Jul 13
9 Apr 15
10 Jul3 13
9 Apr 15
10 Jul 13
01 Jul 14
9 Apr 15
—
17 Jul 14
9 Apr 15
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
$0.0820
$0.0062
$0.0580
$0.0062
$0.0580
$0.0062
$0.0580
$0.0200
$0.0067
—
$0.0200
$0.0067
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
$0.475
$0.450
$0.450
$0.450
$0.450
$0.450
$0.450
$0.400
$0.400
—
$0.400
$0.400
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
15 Nov 17
15 Nov 17
15 Nov 15
15 Nov 17
15 Nov 15
15 Nov 17
15 Nov 15
15 Nov 15
15 Nov 17
—
15 Nov 15
15 Nov 17
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
733,334
—
570,000
—
560,000
100,000
—
—
120,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
100%
—
100%
—
100%
100%
—
—
100%
—
—
1 Mr Dunmore and Mr Herrington retired as a directors 26 November 2014.
2 Mr Elsholz resigned from employment on 30 November 2014. Options were awarded in respect of prior service periods.
3. During 2015, Mr Herrington had 450,000 options cancelled out of the 1,800,000 options granted in the prior year.
28
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
Executive Directors and Other Key Management Personnel
G. Remuneration Details (continued)
Table 3: Options Granted as Part of Remuneration
VALUE OF OPTIONS
GRANTED DURING THE
YEAR
$
VALUE OF OPTIONS
LAPSED/ CANCELLED
DURING THE YEAR
$
REMUNERATION
CONSISTING OF OPTIONS
FOR THE YEAR
%
2015
Non-Executive Directors
Andrew Whittle
William Dunmore1
Wrixon Gasteen
Robert Hubbard
J. Thomas Wilson
Peter Moore
Richard Cottee
Michael Herrington
Bruce Elsholz2
Daniel White
Leon Devaney
Michael Bucknill
Robbert Willink
2014
Non-Executive Directors
Andrew Whittle
William Dunmore
Wrixon Gasteen
Robert Hubbard
J. Thomas Wilson
Peter Moore
VALUE OF OPTIONS
GRANTED DURING THE
YEAR
$
VALUE OF OPTIONS
LAPSED DURING THE
YEAR
$
REMUNERATION
CONSISTING OF OPTIONS
FOR THE YEAR
%
—
—
—
—
—
—
—
—
2,297
2,790
3,125
4,211
4,611
—
—
—
—
—
—
—
—
—
—
—
—
—
(2,655)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(55,928)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
18
9
8
9
—
—
Executive Directors and Other Key Management Personnel
Richard Cottee
Michael Herrington
Bruce Elsholz
Daniel White
Leon Devaney
Michael Bucknill
Robbert Willink
1 Retired effective 26 November 2014
2 Resigned effective 30 November 2014
—
148,500
33,060
42,534
32,480
—
—
No other options were exercised during either year, and no shares were issued on exercise of compensation options.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
29
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
G. Remuneration Details (continued)
Table 4: Shareholdings of Key Management Personnel
HELD AT
BEGINNING OF
YEAR
HELD AT DATE
OF
APPOINTMENT
ON MARKET
PURCHASE
RECEIVED ON
EXERCISE OF
OPTIONS
NET CHANGE
OTHER
HELD AT DATE
OF
DEPARTURE
HELD AT END
OF YEAR
Non-Executive Directors
Andrew Whittle
William Dunmore
Wrixon Gasteen
Robert Hubbard
J. Thomas Wilson
Peter Moore
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
133,680
133,680
183,743
183,743
97,000
104,000
64,100
N/A
—
N/A
—
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
64,100
N/A
—
—
—
102,364
—
—
—
55,900
—
—
—
—
—
Executive Directors and Other Key Management Personnel
Richard Cottee
Michael Herrington
Daniel White
Bruce Elsholz1
Leon Devaney
Michael Bucknill
Robbert Willink
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
208,683
208,683
200,000
200,000
288,000
288,000
—
—
110,000
110,000
31,000
—
—
—
1 Resigned effective 30 November 2014
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
31,000
N/A
—
227,700
—
50,000
—
—
—
—
—
100,000
—
25,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(7,000)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
N/A
183,743
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
236,044
133,680
—
183,743
97,000
97,000
120,000
64,100
—
—
—
—
436,383
208,683
250,000
200,000
288,000
288,000
N/A
—
210,000
110,000
56,000
31,000
—
—
30
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
G. Remuneration Details (continued)
Table 5: Option Holdings of Key Management Personnel
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
William Dunmore1
Wrixon Gasteen
Robert Hubbard
J. Thomas Wilson
Peter Moore
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
900,000
900,000
—
280,000
1,000,000
1,000,000
—
N/A
—
N/A
—
N/A
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Executive Directors and Other Key Management Personnel
Richard Cottee
Michael Herrington
Daniel White
Bruce Elsholz
Leon Devaney
Michael Bucknill
Robbert Willink
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
34,584,407
34,584,407
2,700,000
900,000
1,643,334
929,200
1,170,000
600,000
560,000
—
—
N/A
—
N/A
1 Retired, effective 26 November 2014.
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,800,000
450,000
733,334
370,500
570,000
504,000
560,000
430,000
—
450,000
—
—
—
—
(280,000)
—
—
—
—
—
—
—
—
—
—
(450,000)
—
(600,000)
(19,200)
(400,000)
—
—
—
—
—
—
—
900,000
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
1,140,500
N/A
N/A
N/A
N/A
N/A
N/A
N/A
900,000
900,000
N/A
—
1,000,000
1,000,000
—
—
—
—
—
—
34,584,407
34,584,407
2,250,000
2,700,000
1,493,334
1,643,334
N/A1
1,170,000
1,064,000
560,000
430,000
—
450,000
—
The vesting profile for options held at the end of the year was as follows:
HOLDINGS AT END OF YEAR
VESTED DURING THE YEAR
EXERCISABLE AT END OF YEAR
Non-Executive Directors
Andrew Whittle
Wrixon Gasteen
2015
2014
2015
2014
900,000
900,000
1,000,000
1,000,000
Executive Directors and Other Key Management Personnel
Richard Cottee
Michael Herrington
Daniel White
Bruce Elsholz
Leon Devaney
Michael Bucknill
Robbert Willink
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
34,584,407
34,584,407
2,250,000
2,700,000
1,183,333
1,643,334
N/A
1,170,000
1,064,000
560,000
430,000
—
450,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
100,000
—
120,000
—
300,000
300,000
333,333
333,333
9,683,634
9,683,634
300,000
300,000
733,333
1,643,334
N/A
1,170,000
560,000
560,000
100,000
—
120,000
—
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
31
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
G. Remuneration Details (continued)
For each grant of options included in the tables 1 to 5 above, the percentage of the grant that was vested 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 26), 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 COMPENSAION BENEFITS (OPTIONS)
NAME
Year Granted
Andrew Whittle
William Dunmore
Wrixon Gasteen
Richard Cottee
Michael Herrington
Daniel White
Leon Devaney
Michael Bucknill
Robbert Willink
2013
2009
2008
2013
2013
2014
2013
2015
2014
2013
2010
2015
2014
2015
2015
Vested
%
33
100
100
33
28
—
33
—
100
100
100
—
100
23
27
Forfeited
%
—
—
—
—
—
25
—
—
—
—
—
—
—
—
—
Financial Years in
which Options may
Vest
2014 to 2017
—
—
2014 to 2017
2014 to 2017
2015 to 2017
2014 to 2017
2015 to 2017
—
—
—
2015 to 2017
—
2015 to 2017
2015 to 2017
Maximum Value of
Grant yet to Vest
$
66,252
—
—
73,613
3,094,211
3,140
66,252
1,175
—
—
—
1,316
—
1,106
1,106
Deferred Share Holdings of Key Management Personnel
Under the group’s Employee Rights Plan, eligible employees may receive rights to deferred shares of Central Petroleum Limited. The rights
are granted in respect of a plan year which commences 1 July each year. The share rights remain unvested until the end of the performance
period which is three years commencing from the start of each plan year. Eligible employee must still be in the employment of Central
Petroleum Limited as at the vesting date for the rights to vest.
Final vesting percentages are determined by a combination of performance hurdles in respect of a combination of absolute total shareholder
return and relative total shareholder return compared to a specific group of Exploration & Production companies as determined by the Board.
The number of rights to be granted to eligible employees is determined based on the maximum long term incentive amount applicable for
each employee, being either a fixed dollar amount or a percentage of the employee’s base salary, divided by the volume weighted average
share price (VWAP) at the start of the plan year.
The maximum number of rights to ordinary shares in the Company under the long term incentive plan held during the financial year by other
key management personnel of the consolidated entity, including their personally related parties, are set out below:
Table 6: Deferred Share Holdings of Key Management Personnel
NUMBER OF
RIGHTS HELD AT
START OF YEAR
MAXIMUM NUMBER
GRANTED AS
COMPENSATION
CANCELLED
DURING THE YEAR
CONVERTED TO
SHARES
NUMBER OF
RIGHTS HELD AT
END OF YEAR
(UNVESTED)
Executive Directors and Other Key Management Personnel
Richard Cottee
Michael Herrington
Daniel White
Leon Devaney
Michael Bucknill
Robbert Willink
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
330,000
—
278,571
—
274,285
—
262,286
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
330,000
—
278,571
—
274,285
—
262,286
—
32
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
H. Executive Service Agreements
The details of service agreements of the key management personnel of the Consolidated Entity are as follows:
Richard Cottee, Managing Director and Chief Executive Officer
The term of the agreement expires 29 June 2018.
Mr Cottee’s base salary is presently $574,162 per annum. In addition, superannuation at 9.5 percent is applicable. The salary is
reviewed annually.
In order to terminate employment, a 6 month period of notice is required by either party, except in certain exceptional
circumstances (such as breach or gross misconduct) where a shorter time applies.
Mike Herrington, Executive Director and Chief Operating Officer
The term of the current agreement expires 28 January 2016.
Extension term of the current agreement expires 29 January 2019
Mr Herrington’s base salary is presently $465,000 per annum. In addition, superannuation at 9.5 percent is applicable. The salary
is reviewed annually.
In order to terminate employment, a 3 month period of notice is required by either party, except in certain exceptional
circumstances (such as breach or gross misconduct) where a shorter time applies.
Leon Devaney, Chief Financial Officer
The term of the agreement expires 15 November 2015.
Extension term of the current agreement expires 16 November 2018
Mr Devaney’s base salary is presently $391,500 per annum. In addition, superannuation at 9.5 percent is applicable. The salary is
reviewed annually.
In order to terminate employment, a 3 month period of notice is required by either party, except in certain exceptional
circumstances (such as breach or gross misconduct) where a shorter time applies.
Daniel White, Group General Counsel and Company Secretary
The term of the agreement expires 29 November 2017.
Mr White’s base salary is presently $385,000 per annum. In addition, superannuation at 9.5 percent is applicable. The salary is
reviewed annually.
In order to terminate employment, a 3 month period of notice is required by either party, except in certain exceptional
circumstances (such as breach or gross misconduct) where a shorter time applies.
Michael Bucknill, General Manager, Exploration
The term of the agreement expires 30 June 2017.
Mr Bucknill’s base salary is presently $320,000 per annum. In addition, superannuation at 9.5 percent is applicable. The salary is
reviewed annually.
In order to terminate employment, a 3 month period of notice is required by either party, except in certain exceptional
circumstances (such as breach or gross misconduct) where a shorter time applies.
Robbert Willink, Exploration Advisor
The term of the agreement expires 30 June 2017.
Mr Willink’s base salary is presently $340,000 per annum. In addition, superannuation at 9.5 percent is applicable. The salary is
reviewed annually.
In order to terminate employment, a 3 month period of notice is required by either party, except in certain exceptional
circumstances (such as breach or gross misconduct) where a shorter time applies.
Bruce Elsholz, Chief Financial Officer
The term of the agreement expires 30 August 2017.
Mr Elsholz’s base salary is presently $315,000 per annum. In addition, superannuation at 9.5 percent is applicable. The salary is
reviewed annually.
Mr Elsholz resigned his position of Company Secretary effective 25 August 2014 and resigned from Central on 30 November 2014.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
33
DIRECTORS’ REPORT
FOR THE YEAR ENDED 30 JUNE 2015
I. Non-Executive Director Fee Arrangements
The Company has engaged all Directors pursuant to written service agreements. The terms of appointment are subject to the Company’s
Constitution. The Company maintains an appropriate level of Directors’ and Officers’ Liability Insurance and provide rights relating to
indemnity, insurance, and access to documents.
The table below summarises the Non‐Executive Director fees for 2015.
BOARD FEES (PER ANNUM)
Chairman
Non‐Executive Director
COMMITTEE FEES (PER ANNUM)
Audit & Risk
Remuneration
Nomination
Chair
Member
Chair
Member
Chair
Member
$95,000.00
$65,000.00
$10,000.00
$5,000.00
$10,000.00
$5,000.00
$10,000.00
$5,000.00
The Directors also receive superannuation benefits except for Messrs. Gasteen, and Wilson, who reside outside of Australia.
Signed in accordance with a resolution of the Directors:
Richard Cottee
Managing Director
Brisbane
23 September 2015
34
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
Auditor’s Independence Declaration
As lead auditor for the audit of Central Petroleum Limited for the year ended 30 June 2015, I declare
that to the best of my knowledge and belief, there have been:
a) no contraventions of the auditor independence requirements of the Corporations Act 2001 in
relation to the audit; and
b) no contraventions of any applicable code of professional conduct in relation to the audit.
This declaration is in respect of Central Petroleum Limited and the entities it controlled during the
period.
Michael Shewan
Partner
PricewaterhouseCoopers
Brisbane
23 September 2015
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.
35
CORPORATE GOVERNANCE STATEMENT
Central Petroleum Limited and the Board are committed to achieving and demonstrating high standards of corporate governance. The
Company has reviewed its corporate governance practices against the Corporate Governance Principles and Recommendations (3rd edition)
published by the ASX Corporate Governance Council.
The 2015 Corporate Governance Statement is dated as at 30 June 2015 and reflects the corporate governance practices in place throughout
the 2015 financial year. The Company’s Corporate Governance Statement undergoes periodic review by the Board. A description of the
Group’s current corporate governance practices is set out in the Group’s Corporate Governance Statement which can be viewed at
www.centralpetroleum.com.au/about/corporate‐governance/.
36
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
FINANCIAL REPORT
CONTENTS
Financial Statements
Consolidated Statement of Profit or Loss and Other Comprehensive Income ................... 38
Consolidated Statement of Financial Position .................................................................... 39
Consolidated Statement of Changes in Equity .................................................................... 40
Consolidated Statement of Cash Flows .............................................................................. 41
Notes to the Consolidated Financial Statements ............................................................................... 42
Directors’ Declaration ......................................................................................................................... 84
Independent Auditor’s Report to the Members ................................................................................ 85
ASX Additional Information ................................................................................................................ 87
Interests in Petroleum Permits and Pipeline Licences ....................................................................... 89
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:
Level 32, 400 George Street
Brisbane, Queensland 4000
A description of the nature of the consolidated entity’s operations and its principal activities is included in the review of operations and
activities which forms part of the directors’ report on pages 4 to 21. These pages are not part of these financial statements.
The financial statements were authorised for issue by the directors on 23 September 2015. The directors have the power to amend and
reissue the financial statements.
Through the use of the internet we have ensured that our corporate reporting is timely and complete. Press releases, financial reports and
other information are available via the links on our website: www.centralpetroleum.com.au
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
37
CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER
COMPREHENSIVE INCOME
FOR THE YEAR ENDED 30 JUNE 2015
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
Impairment expense
Loss before income tax
Income tax credit
Loss for the year
Other comprehensive loss for the year, net of tax
NOTE
2015
$
2014
$
22(a)
22(b)
22(c)
2
30(d)
3
3 & 22(d)
3
4
20
10,313,266
(10,117,038)
3,718,102
(3,016,494)
196,228
701,608
7,480,298
(2,246,683)
(1,938,425)
—
(2,707,589)
(5,018,180)
(7,655,931)
(3,748,714)
(12,092,042)
1,530,668
(2,818,231)
(2,517,230)
(1,914,004)
(1,127,155)
(3,120,279)
(4,659,886)
(1,040,975)
—
(27,731,038)
(14,965,484)
—
4,107,498
(27,731,038)
(10,857,986)
—
—
Total comprehensive loss for the year
(27,731,038)
(10,857,986)
Total comprehensive loss attributable to members of the parent
entity
(27,731,038)
(10,857,986)
Basic and diluted loss per share (cents)
21
(7.63)
(3.42)
The accompanying notes form part of these financial statements.
38
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
AS AT 30 JUNE 2015
NOTE
2015
$
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
6
7
8
9
10
11
12
13
14
15
16
17
16
17
3,516,139
5,869,332
2,136,673
1,755,736
10,330,474
2,953,300
1,940,983
1,000,000
13,277,880
16,224,757
58,577,415
8,898,767
12,052
2,075,733
3,906,270
46,266,152
16,869,693
19,521
2,423,185
3,906,270
73,470,237
69,484,821
86,748,117
85,709,578
7,707,897
7,921,129
2,060,330
10,476,308
255,760
2,716,068
17,689,356
13,448,136
39,536,722
6,375,539
23,761,593
5,431,136
45,912,261
29,192,729
63,601,617
42,640,865
23,146,500
43,068,713
18
19
20
160,785,182
16,695,379
(154,334,061)
155,223,040
14,448,696
(126,603,023)
23,146,500
43,068,713
The accompanying notes form part of these financial statements.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
39
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEAR ENDED 30 JUNE 2015
CONTRIBUTED
EQUITY
RESERVES
ACCUMULATED
LOSSES
$
TOTAL
$
Total equity at 1 July 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
—
—
—
—
—
—
(10,857,986)
—
(10,857,986)
—
(10,857,986)
(10,857,986)
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)
24,965,018
2,818,231
1,497,526
—
—
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
Total loss for the year
Other comprehensive loss
Total comprehensive loss for the year
—
—
—
—
—
—
(27,731,038)
—
(27,731,038)
—
(27,731,038)
(27,731,038)
Transactions with owners in their
capacity as owners
Share based payments
Options issued for financing
Share and option issues
Share issue costs
—
—
6,000,000
(437,858)
2,246,683
—
—
5,562,142
2,246,683
—
—
—
—
—
2,246,683
—
6,000,000
(437,858)
7,808,825
Balance at 30 June 2015
160,785,182
16,695,379
(154,334,061)
23,146,500
The accompanying notes form part of these financial statements.
40
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
CONSOLIDATED STATEMENT OF CASH FLOW
FOR THE YEAR ENDED 30 JUNE 2015
Cash flows from operating activities
Receipts from customers
Interest received
Other income
Interest & borrowing costs
Payments to suppliers and employees (inclusive of GST)
NOTE
2015
$
2014
$
10,980,363
143,396
3,420,536
(286,761)
(24,857,867)
2,105,060
406,273
7,931,000
(375,000)
(9,589,572)
Net cash (outflow)/inflow from operating activities
26
(10,600,333)
477,761
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 property, plant and equipment
Redemption / (Acquisition) of security deposits and bonds
(21,776,201)
—
—
—
960,000
345,352
(3,344,271)
—
(20,595,871)
(1,914,004)
—
(566,466)
Net cash inflow/(outflow) from investing activities
(20,470,849)
(26,420,612)
Cash flows from financing activities
Proceeds from the issue of shares and options
Proceeds from borrowings
Repayment of borrowings
Net cash inflow from financing activities
5,562,142
19,000,000
(305,295)
9,965,018
25,000,000
—
24,256,847
34,965,018
Net (decrease)/increase in cash and cash equivalents
(6,814,335)
9,022,167
Cash and cash equivalents at the beginning of the financial year
10,330,474
1,308,307
Cash and cash equivalents at the end of the financial year
Non‐cash financing and investing activities
3,516,139
10,330,474
6
27
The accompanying notes form part of these financial statements.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
41
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
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 2015 the
Group incurred a loss before tax of $27,731,038 (2014: $14,965,484), net cash outflow from operating activities of $10,600,333 (2014: inflow
of $477,761) and as of that date, the Group’s current liabilities exceeded its current assets by $4,411,476 (2014: net current assets of
$2,776,621). These results are consistent with our exploration, appraisal and development activities and also reflect a ramp‐up phase in the
Palm Valley gas field and completion of the Dingo gas field.
As at 30 June 2015 the Group had cash assets including joint arrangement balances amounting to $3,516,139. 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.
Over the next 12 months, additional funds will be required as existing cash balances, combined with expected cash inflows from the Group’s
production operations, are not expected to be sufficient by themselves to fund the Mereenie acquisition commitments (notably $15 million
comprising a free‐carry work program for Santos ($5 million) and a deferred acquisition payment ($10 million) due in June 2016).
The primary focus for the Group’s required funding above is via new supportable debt generated by new gas sales agreements (GSA’s)
connected with the North East Gas Interconnector (NEGI) pipeline. To this end, Central has entered into two non‐binding letters of agreement
for the sale of gas subject to the NEGI pipeline Final Investment Decision (FID), both from major gas purchasers on the east coast.
Given the significant installed capacity already invested at Mereenie, further GSA’s via the NEGI indicate that sufficient debt capital could be
raised beyond required project costs to fund the future Mereenie acquisition commitments whilst still maintaining very commercially
acceptable debt service coverage ratios. Given the Group’s existing GSA’s are all long‐term fixed‐price CPI escalated contracts, and future
NEGI related GSA’s are expected to have a similar pricing construct, utilising debt capital is considered by the Group to be cost efficient (low
interest rates) and appropriate in a capital structuring sense. Central’s existing banker, Macquarie Bank Ltd, has provided a letter of support
for expanding Central’s existing $90 million debt facility to cover required development costs and up to a further $15 million to specifically
cover any remaining Mereenie acquisition costs. Such increased debt funding would be subject to sufficient gas sales agreements,
Macquarie’s receipt of all internal approvals, and the usual and customary conditions precedent to the provision of finance to Central.
In addition to NEGI related GSA debt capital, the Group has several other alternative sources of funding it is actively considering and will
select the one which is most aligned with creating shareholder value at the time. The two most notable include a sell down of a partial
interest in Central’s existing producing assets (Mereenie, Palm Valley and Dingo) or approaching the equity markets for a capital raising.
Alternatively a combination of the above could be implemented depending on the prevailing economic and market conditions. Further to
these sources of funding, if required, the Company has access to an Equity Line of Credit (ELOC) Facility of $10 million with Long State
Investment Limited (LSI), the terms of which are set out in Note 18(g).
If additional funding does not materialise at the appropriate time and for the appropriate amounts then there is a material uncertainty that
may cast significant doubt on whether the Group will continue as a going concern and, therefore, whether it will realise its assets and settle
its liabilities and commitments in the normal course of business and at the amounts stated in the financial report.
The Directors believe that the Group 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 2015. 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.
42
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(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 2014 where such application would result
in them being applied prior to them becoming mandatory.
(iv)
Historical Cost Convention
These financial statements have been prepared under the historical cost convention.
(v)
Critical Accounting Judgements and Key Sources of Estimate Uncertainty
In the application of the Group’s accounting policies, management is required to make judgements, estimates and assumptions regarding
carrying values of assets and liabilities that are not readily apparent from other sources. The estimates and assumptions are based on
historical experience and various other factors that are believed to be reasonable under the circumstances, the results of which form the
basis of making the judgements. Actual results may differ from these estimates. Key judgements in applying the entity’s accounting policies
are required in the following areas:
Rehabilitation
The Group recognises any obligations for removal and restoration that are incurred during a particular period as a consequence of having
undertaken exploration and evaluation activity. The Group makes provision for future restoration expenditure relating to work previously
undertaken based on management’s estimation of the work required.
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.
Impairment of Other Non-financial Assets
Other non‐financial assets, including property, plant and equipment and goodwill are tested for impairment annually or whenever events or
changes in circumstances indicate that the carrying amount may not be recoverable. For the purposes of assessing impairment, assets are
grouped at the lowest levels for which there are separately identifiable cash inflows which are largely independent of the cash inflows from
other assets or groups of assets (cash‐generating units). The Group is required to use assumptions in respect of future commodity prices,
foreign exchange rates, interest rates and operating costs in determining expected future cash flows from operations.
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.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 43
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(b)
Principles of Consolidation
(i)
Subsidiaries
The consolidated financial statements incorporate the assets and liabilities of all subsidiaries of Central Petroleum Limited (“Company” or
“Parent Entity”) as at 30 June and the results of all subsidiaries for the year then ended. Central Petroleum Limited and its subsidiaries
together are referred to in this financial report as the Group or the Consolidated Entity.
Subsidiaries are all entities (including structured entities) over which the group has control. The group controls an entity when the group is
exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power
to direct the activities of the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the group.
They are deconsolidated from the date that control ceases. The acquisition method is used to account for business combinations by the
Group.
Intercompany transactions, balances and unrealised gains on transactions between Group companies are eliminated. Unrealised losses are
also eliminated unless the transaction provides evidence of the impairment of the asset transferred. Accounting policies of subsidiaries have
been changed where necessary to ensure consistency with the policies adopted by the Group.
Non‐controlling interests (if applicable) in the results and equity of subsidiaries are shown separately in the statement of comprehensive
income, statement of changes in equity and statement of financial position respectively.
(ii)
Joint Arrangements
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.
(iii)
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.
(ii)
Transactions and Balances
Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions.
Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end exchange rates of
monetary assets and liabilities denominated in foreign currencies are recognised in profit or loss, except when they are deferred in equity as
qualifying cash flow hedges and qualifying net investment hedges or are attributable to part of the net investment in a foreign operation.
44
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(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. Revenue from take or pay contracts is recognised in earnings when the product is taken by the customer or their right to take
product expires. It is recorded as unearned revenue when it has not been taken and a right to take it in future still exists.
(ii)
Interest Income
Interest revenue is recognised on a time proportionate basis that takes into account the effective yield on the financial assets.
(f)
Government Grants
Grants from the government, including research and development concessions, are recognised at their fair value where there is a reasonable
assurance that the grant or refund will be received and the Group has or will comply with any conditions attaching to the grant or refund.
Research and development grants are recognised as other income in the profit and loss where they relate to exploration expenditure which
has been expensed in the profit and loss.
(g)
Income Tax
The income tax expense or revenue for the period is the tax payable on the current period’s taxable income based on the applicable income
tax rate adjusted by changes in deferred tax assets and liabilities attributable to temporary differences and to unused tax losses.
The current income tax charge is calculated on the basis of the tax laws enacted or substantially enacted at the end of the reporting period
in the countries where entities in the Group generate taxable income.
Deferred tax is provided in full, using the liability method, on temporary differences arising between the tax bases of assets and liabilities
and their carrying amounts in the consolidated financial statements. Deferred tax liabilities are not recognised if they arise from the initial
recognition of goodwill. Deferred tax is also not accounted for if it arises from initial recognition of an asset or liability in a transaction other
than a business combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Deferred income tax is
determined using tax rates (and laws) that have been enacted or substantially enacted by the end of the reporting period and are expected
to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled.
Deferred tax assets are recognised for deductible temporary differences and unused tax losses only if it is probable that future taxable
amounts will be available to utilise those temporary differences and losses.
Deferred tax liabilities and assets are not recognised for temporary differences between the carrying amount and tax bases of investments
in foreign operations where the Group is able to control the timing of the reversal of the temporary differences and it is probable that the
differences will not reverse in the foreseeable future.
Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets and liabilities and when the
deferred tax balances relate to the same taxation authority. Current tax assets and tax liabilities are offset where the entity has a legally
enforceable right to offset and intends either to settle on a net basis, or to realise the asset and settle the liability simultaneously.
Central Petroleum Limited and its wholly‐owned Australian controlled entities have implemented the tax consolidation legislation. As a
consequence, these entities are taxed as a single entity and the deferred tax assets and liabilities of these entities are set off in the
consolidated financial statements. Current and deferred tax is recognised in profit or loss, except to the extent that it relates to items
recognised in other comprehensive income or directly in equity. In this case, the tax is also recognised in other comprehensive income or
directly in equity, respectively.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 45
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Leases
(h)
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.
(i)
Impairment of Assets
Goodwill and intangible assets that have an indefinite useful life are not subject to amortisation and are tested annually for impairment or
more frequently if events or changes in circumstances indicate that they might be impaired. Other assets are tested for impairment whenever
events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the
amount by which the asset's carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset's fair value
less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are
separately identifiable cash inflows which are largely independent of the cash inflows from other assets or groups of assets (cash‐generating
units). Non‐financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the impairment at the end of
each reporting period.
Cash and Cash Equivalents
(j)
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.
(k)
Trade Receivables
Trade receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, less
provision for impairment. Trade receivables are generally due for settlement within 90 days. They are presented as current assets unless
collection is not expected for more than 12 months after the reporting date.
Collectability of trade receivables is reviewed on an ongoing basis. Debts which are known to be uncollectible are written off by reducing the
carrying amount directly. An allowance account (provision for impairment of trade receivables) is used when there is objective evidence that
the Group will not be able to collect all amounts due according to the original terms of the receivables. Significant financial difficulties of the
debtor, probability that the debtor will enter bankruptcy or financial reorganisation, and default or delinquency in payments (more than 90
days overdue) are considered indicators that the trade receivable is impaired. The amount of the impairment allowance is the difference
between the asset's carrying amount and the present value of estimated future cash flows, discounted at the original effective interest rate.
Cash flows relating to short‐term receivables are not discounted if the effect of discounting is immaterial.
The amount of the impairment loss is recognised in profit or loss within other expenses. When a trade receivable for which an impairment
allowance had been recognised becomes uncollectible in a subsequent period, it is written off against the allowance account. Subsequent
recoveries of amounts previously written off are credited against other expenses in profit or loss.
46
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Inventories
(l)
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.
(m) Other Financial Assets
Classification
The Group’s financial assets consist of loans and receivables. These are non‐derivative financial assets with fixed or determinable payments
that are not quoted in an active market. They are included in current assets, except for those with maturities greater than 12 months after
the reporting period which are classified as non‐current assets. Loans and receivables are included in trade and other
Receivables (Note 7) and other financial assets (Note 13) 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.
(n) Property, Plant and Equipment – Development and Production Assets
Assets in Development
The costs of oil and gas properties in the development phase are separately accounted for and include costs transferred from exploration
and evaluation assets once technical feasibility and commercial viability of an area of interest are demonstrable, 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.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
47
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(o) Property, Plant and Equipment – Other than Development and Production
Assets
All property, plant and equipment is stated at historical cost less depreciation. Historical cost includes expenditure that is directly attributable
to the acquisition of the items. Cost may also include transfers from equity of any gains or losses on qualifying cash flow hedges of foreign
currency purchases of property, plant and equipment.
Subsequent costs are included in the asset's carrying amount or recognised as a separate asset, as appropriate, only when it is probable that
future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. The carrying
amount of any component accounted for as a separate asset is derecognised when replaced. All other repairs and maintenance are charged
to profit or loss during the reporting period in which they are incurred.
Land is not depreciated. Depreciation of plant and equipment is calculated on a reducing balance basis so as to write off the net costs of
each asset over the expected useful life. The assets' residual values and useful lives are reviewed, and adjusted if appropriate, at each
statement of financial position date.
An asset's carrying amount is written down immediately to its recoverable amount if the asset's carrying amount is greater than its estimated
recoverable amount.
Gains and losses on disposals are determined by comparing proceeds with the carrying amount. These are included in the profit or loss.
The expected useful life for each class of depreciable assets is:
Class of Fixed Asset
Buildings
Leasehold Improvements
Plant and Equipment
Motor Vehicles
Expected Useful Life
40 years
2 – 6 years
2 – 30 years
5 – 10 years
(p) Exploration Expenditure
Exploration and evaluation costs are expensed as incurred. Acquisition costs of rights to explore are 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.
(q) Goodwill
Goodwill arising on the acquisition of subsidiaries is not amortised but it is tested for impairment annually, or more frequently if events or
changes in circumstances indicate a potential impairment. Goodwill is carried at cost less accumulated impairment losses.
Goodwill is allocated to cash generating units for the purpose of impairment testing. The allocation is made to those cash‐generating units
or groups of cash‐generating units that are expected to benefit from the business combination in which the goodwill arose. The units or
groups of units are identified at the lowest level at which goodwill is monitored for internal management purposes, being the operating
segments (Note 22).
(r)
Trade and Other Payables
These amounts represent liabilities for goods and services provided to the Group prior to the end of financial year which are unpaid. The
amounts are unsecured and are usually paid within 30 days of recognition, except contributions to Joint Arrangements that are settled in
line with the Joint Operating Agreements. Trade and other payables are presented as current liabilities unless payment is not due within 12
months from the reporting date. They are recognised initially at their fair value and subsequently measured at amortised cost using the
effective interest method.
48
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(s) Provisions
(i)
Restoration
The Group records the present value of the estimated cost of legal and constructive obligations to restore operating locations in the period
in which the obligation arises. The nature of restoration activities includes the removal of facilities, abandonment of wells and restoration of
affected areas.
A restoration provision is recognised and updated at different stages of the development and construction of a facility and then reviewed on
an annual basis. When the liability is initially recorded, the estimated cost is capitalised by increasing the carrying amount of the related
exploration and evaluation assets or property plant and equipment.
Over time, the liability is increased for the change in the present value based on a pre‐tax discount rate appropriate to the risks inherent in
the liability. The unwinding of the discount is recorded as an accretion charge within finance costs.
The carrying amount capitalised in property plant and equipment is depreciated over the useful life of the related producing asset (refer to
Note 1(n)).
Costs incurred that relate to an existing condition caused by past operations and do not have a future economic benefit are expensed.
(ii)
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.
(t)
Employee Benefits
(i)
Short-term Obligations
Liabilities for wages and salaries, including non‐monetary benefits, annual leave and long service leave expected to be settled within
12 months after the end of the period in which the employees render the related service are recognised in respect of employees' services up
to the end of the reporting period and are measured at the amounts expected to be paid when the liabilities are settled. The liability for
annual leave and long service leave is recognised in the provision for employee benefits. All other short‐term employee benefit obligations
are presented as payables.
(ii)
Other Long-term Employee Benefit Obligations
The liability for long service leave which is not expected to be settled within 12 months after the end of the period in which the employees
render the related service is recognised in the provision for employee benefits and measured as the present value of expected future
payments to be made in respect of services provided by employees up to the end of the reporting period. Consideration is given to expected
future wage and salary levels, experience of employee departures and periods of service. Expected future payments are discounted using
market yields at the end of the reporting period with terms to maturity and currency that match, as closely as possible, the estimated future
cash outflows.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED 49
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(t)
Employee benefits (continued)
(iii)
Share-based Payments
Share‐based compensation benefits are provided to employees (including directors) by Central Petroleum Limited.
The fair value of options or rights granted is recognised as an employee benefits expense with a corresponding increase in equity. The total
amount to be expensed is determined by reference to the fair value of the 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.
(u) Contributed Equity
Ordinary shares are classified as equity.
Incremental costs directly attributable to the issue of new shares or options are shown in equity as a deduction, net of tax, from the proceeds.
(v) Dividends
Provision is made for the amount of any dividend declared, being appropriately authorised and no longer at the discretion of the entity, on
or before the end of the reporting period but not distributed at the end of the reporting period.
(w) Earnings Per Share
Basic Earnings Per Share
(i)
Basic earnings per share is calculated by dividing the profit attributable to owners of the Company, excluding any costs of servicing equity
other than ordinary shares by the weighted average number of ordinary shares outstanding during the financial year.
(ii)
Diluted Earnings Per Share
Diluted earnings per share adjusts the figures used in the determination of basic earnings per share to take into account the after income tax
effect of interest and other financing costs associated with dilutive potential ordinary shares and the weighted average number of additional
ordinary shares that would have been outstanding assuming the exercise of all dilutive potential ordinary shares.
(x) Goods and Services Tax (GST)
Revenues, expenses and assets are recognised net of the amount of GST, unless the GST incurred is not recoverable from the taxation
authority. In this case it is recognised as part of the cost of acquisition of the asset or as part of the expense.
Receivables and payables are stated inclusive of the amount of GST receivable or payable. The net amount of GST recoverable from, or
payable to, the taxation authority is included with other receivables or payables in the statement of financial position.
Cash flows are presented on a gross basis. The GST components of cash flows arising from investing or financing activities which are
recoverable from, or payable to the taxation authority, are presented as operating cash flows.
50
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(y) Parent Entity Financial Information
The financial information for the parent entity, Central Petroleum Limited, disclosed in Note 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 standalone taxpayer in its own right.
In addition to its own current and deferred tax amounts, Central Petroleum Limited also recognises the current tax liabilities or assets and
the deferred tax assets arising from unused tax losses from controlled entities, where permitted to recognise such assets under accounting
standards.
(z) Business Combinations
Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the
consideration transferred, measured at acquisition date fair value and the amount of any non‐controlling interest in the acquiree. For each
business combination, the Group elects whether it measures the non‐controlling interest in the acquiree at fair value or at the proportionate
share of the acquiree’s identifiable net assets. Acquisition costs incurred are expensed and included in administrative expenses.
When the Group acquires a business, it assesses the financial assets and liabilities assumed for appropriate classification and designation in
accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the
separation of embedded derivatives in host contracts by the acquiree.
If the business combination is achieved in stages, the acquisition date fair value of the acquirer’s previously held equity interest in the
acquiree is remeasured to fair value at the acquisition date through profit or loss.
Any contingent consideration to be transferred by the acquirer will be recognised at fair value at the acquisition date. Subsequent changes
to the fair value of the contingent consideration that is deemed to be an asset or liability will be recognised in accordance with AASB 139 in
profit or loss. If the contingent consideration is classified as equity it will not be remeasured. Subsequent settlement is accounted for within
equity. In instances where the contingent consideration does not fall within the scope of AASB 139, it is measured in accordance with the
appropriate AASB.
Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised for non‐
controlling interest over the net identifiable assets acquired and liabilities assumed. If this consideration is lower than the fair value of the
net assets of the subsidiary acquired, the difference is recognised in profit or loss.
After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing,
goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group’s cash‐generating units that are
expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquirer are assigned to those units.
Where goodwill forms part of the cash generating unit and part of the operation within that unit is disposed of, the goodwill associated with
the operation disposed of is included in the carrying amount of the operation when determining the gain or loss on disposal of the operation.
Goodwill disposed of in this circumstance is measured based on the relative values of the operation disposed of and the portion of the cash‐
generating unit retained.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
51
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(aa) 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 2014:
•
•
•
•
AASB 2013‐3 Amendments to AASB 136 Recoverable Amount Disclosures for Non‐Financial Assets
AASB 2013‐4 Amendments to Australian Accounting Standards – Novation of Derivatives and Continuation of Hedge Accounting.
Interpretation 21 Accounting for Levies
AASB 2014‐1 Amendments to Australian Accounting Standards
No changes in accounting policies or adjustments to the amounts recognised in the financial statements resulted from the adoptions of these
standards.
(ii)
New Standards and Interpretations not yet Adopted
Certain new accounting standards and interpretations have been published that are not mandatory for 30 June 2015 reporting periods. The
consolidated entity has 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.
2. OTHER INCOME
Interest
Research and development refunds (a)
Other
Total other income
2015
$
2014
$
150,003
7,324,496
5,799
7,480,298
307,274
1,196,296
27,098
1,530,668
(a)
The 2015 amount includes refunds received during the year in respect of the financial year ended 30 June 2014 amounting to $3,251,940.
It also includes $4,072,556 accrued as receivable in respect of the financial year ended 30 June 2015. The refunds relate to exploration
activities which have been expensed in the profit and loss in the current or prior year. The 2014 refund was not previously recognised as
income as the amount and recoverability were uncertain at the time of preparation of the 2014 financial statements.
52
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
3.
EXPENSES
(a)
Loss before income tax includes the following specific expenses:
NOTE
Depreciation (i)
Buildings
Producing assets
Restoration assets
Plant and equipment
Leasehold improvements
Total depreciation
Amortisation (i)
Software
2015
$
844
1,047,939
304,162
1,301,467
42,880
2,697,292
2014
$
7,094
513,435
69,146
502,611
20,824
1,113,110
10,297
14,045
Impairment expense
3(b)
12,092,042
—
Rental expense relating to operating leases – Minimum lease
payments
1,224,562
697,419
Finance costs
Interest charge on Macquarie debt facility (ii)
Interest paid to other suppliers
Borrowing costs on Macquarie and other debt facility (ii)
Amortisation of deferred finance costs (ii)
Accretion charge
2,937,287
16,829
285,210
327,827
181,561
3,748,714
528,067
—
375,000
81,956
55,952
1,040,975
(i)
(ii)
Depreciation and amortisation expense is based on a full year allocation for the Palm Valley gas field (2014: 3 months) and
three months in respect of the Dingo gas pipeline and processing facilities which became ready for use on 1 April 2015. Of
the amounts reported above, $492,000 relates to the Dingo gas field for which no revenue has been recognised in this
financial period.
Finance Costs totaling $3.55 million relate to the Macquarie debt facility for the acquisition of the Palm Valley and Dingo
gas fields and comprise borrowing costs of $613,000 and interest of $2.94 million (refer Note 31(e) for details on the
facility). Of the total $3.55 million, $1.93 million relates to the Dingo gas field which although development was completed
and the PWC GSA commenced on 1 April 2015 did not earn sales revenue as originally anticipated. The balance of
$1.62 million relates to the Palm Valley gas field which anticipated full contract nominations during the year but did not
ramp up revenues until May 2015. The Macquarie facility is secured by the Palm Valley and Dingo gas fields and is serviced
by their respective cash flows.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
53
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
3.
EXPENSES (continued)
(b)
Individually significant items
Impairment of assets
Oil Producing Assets
During the year the group fully impaired the assets relating to its Oil Producing assets in the Amadeus Basin. The impairment was
based on expected future cash flows from the asset. The impairment loss included in the income statement relating to these assets
was $5,420,293.
Property
Real property assets consisting of a warehouse and a residential property in Alice Springs were placed on the market for sale and
were impaired to reflect their recoverable amounts. The impairment loss relating to these assets was $100,822.
Exploration Assets
During the year the following exploration permits were impaired to their recoverable amounts:
EP115
was impaired by $828,800. In light on the impairment of the oil producing assets this permit was impaired by 50 percent
of its previous carrying value. Exploration and evaluation activities continue in the North Mereenie Block (operated by
Santos) under a Farmout agreement with Santos.
EP97
impaired by $5,615,460. Management has impaired this asset to its likely recoverable amount under a potential
divestment of the permit interests.
EP106
impaired by $126,667. Management has impaired this asset to Nil on the basis of a likely relinquishment of the permit.
54
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
4.
INCOME TAX
This note provides an analysis of the group’s income tax expense, shows what amounts are recognised directly in equity and how
the tax credit is affected by non‐assessable and non‐deductible items. It also explains significant estimates made in relation to the
group’s tax position.
(a)
Income tax expense
Current tax
Deferred tax
Income tax expense
(b) Numerical reconciliation of income tax expense and prima facie tax
benefit
Loss before income tax expense
Prima facie tax benefit at 30% (2014: 30%)
Tax effect of amounts which are not deductible in calculating taxable
income:
Non‐deductible expenses
Research and development expenditure
Share based payments
Non‐assessable income
Sub‐total
2015
$
—
—
—
2014
$
—
4,107,498
4,107,498
(27,731,038)
8,319,311
(14,965,484)
4,489,645
(362,625)
(2,714,864)
(674,005)
2,197,349
(439,309)
—
(845,469)
344,365
6,765,166
3,549,232
Under provision in prior year
—
—
Deferred tax assets not recognised
Recognition of previously unrecognised DTA
Income tax expense
(6,765,166)
—
558,266
—
4,107,498
(c) Amounts recognised directly in equity
Aggregate deferred tax arising in the reporting period and not
recognised in net profit or loss or other comprehensive income but
directly debited or credited to equity:
Net deferred tax – debited directly to equity
Deferred tax assets not recognised
Net amounts recognised directly in equity
(d) Tax Losses
110,871
(110,871)
—
Unutilised tax losses for which no deferred tax asset has been recognised
109,823,407
Potential tax benefit at 30%
32,947,022
149,335
(149,335)
—
94,277,733
28,283,320
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
55
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
4.
INCOME TAX (continued)
(e) Deferred tax assets and liabilities
Deferred tax assets
Provisions and accruals
Blackhole expenditure
Borrowing costs
PRRT
Unutilised losses
Total deferred tax assets before set‐offs
Set‐off of deferred tax liabilities pursuant to set‐off provisions
2015
$
2014
$
2,598,851
443,927
112,396
52,254,331
37,756,625
93,166,130
(6,993,154)
2,469,168
627,823
75,422
40,434,838
36,552,974
80,160,225
(8,269,654)
Net deferred tax assets not recognised
86,172,976
71,890,571
Movements
Opening balance at 1 July
(Charged) / Credited to the income statement
Closing balance at 30 June
Deferred tax assets to be recovered after more than 12 months
Deferred tax assets to be recovered within 12 months
Deferred tax liabilities
Acquired income
Capitalised exploration
Property, plant and equipment
PRRT
Other
Total deferred tax assets before set‐offs
Set‐off of deferred tax liabilities pursuant to set‐off provisions
Net deferred tax liabilities
Movements
Opening balance at 1 July
Charged / (Credited) to the income statement
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
8,269,654
(1,276,500)
6,993,154
6,970,577
22,577
6,993,154
1,581
844,254
3,963,768
2,183,551
—
6,993,154
(6,993,154)
—
8,269,654
(1,276,500)
—
6,993,154
6,991,573
1,581
6,993,154
2,949,752
5,319,902
8,269,654
8,253,466
16,188
8,269,654
2,594
2,802,532
5,463,112
—
1,416
8,269,654
(8,269,654)
—
2,949,752
1,212,404
4,107,498
8,269,654
8,253,466
16,188
8,269,654
56
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
5.
REMUNERATION OF AUDITORS
The following fees were paid or payable for services provided by PwC
Australia, the auditor of the Company, its related practices and non‐related
audit firms:
(i) Audit and other assurance services
Audit and review of financial statements
Southern Georgina joint arrangement audit
(ii) Taxation services
Income Tax compliance
Excise consulting services
Other tax related services
(iii) Other services
Magellan transaction due diligence
Remuneration benchmarking
Employee related services
Total remuneration of PwC
6.
CASH AND CASH EQUIVALENTS
Cash at bank and in hand
Made up as follows:
Corporate (a)
Joint arrangements (b)
2015
$
2014
$
141,986
3,000
144,986
8,500
48,957
68,354
125,811
22,000
—
6,698
28,698
299,495
140,777
3,000
143,777
16,311
—
65,955
82,266
181,607
10,000
—
191,607
417,650
3,516,139
10,330,474
3,254,312
261,827
3,516,139
8,740,088
1,590,386
10,330,474
(a) $1,046,123 of this balance relates to cash drawn from the Macquarie Bank Limited debt facility (2014: $2,192,082), and is
restricted to use in the Palm Valley‐Dingo project.
(b) $12,330 of this balance relates to the Group share of cash balances held by the Southern Georgina Joint Arrangement (2014:
$807,914).
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.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
57
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
7.
TRADE AND OTHER RECEIVABLES
Current
Trade receivables
Accrued income (a)
Accrued research and development refund
Other receivables
GST receivables
Prepayments
NOTE
2015
$
2014
$
244,657
858,001
4,072,557
14,540
38,740
640,837
868,282
1,311,154
—
—
286,617
487,247
5,869,332
2,953,300
(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 and natural gas
Spare parts and consumables
Drilling materials and supplies at cost
9. ASSETS HELD FOR SALE
Land and buildings
Exploration assets
137,877
850,064
1,148,732
97,296
534,691
1,308,996
2,136,673
1,940,983
11
355,736
1,400,000
1,000,000
—
1,755,736
1,000,000
During the year the consolidated entity decided to sell a residential property in Alice Springs which was previously used as employee
accommodation. The property was subsequently sold in August 2015. The asset was not allocated to an operating segment in
Note 22.
The consolidated entity also made the decision to divest of its interests in a number of exploration permits and is negotiating with
interested parties. These assets were allocated to the Exploration segment in Note 22.
Non‐recurring fair value measurements
Real property and exploration permits held for sale during the period were measured at the lower of their carrying values and their
fair values less cost to sell at the time of the reclassification. Both items were valued using indicative offers being considered or
being negotiated for the disposal of the assets.
As a result of this impairment losses of $67,072 were recognised in respect of the residential property still held for sale at 30 June
2015 and impairment losses of $5,615,460 were recognised in respect of the exploration permits held for sale.
58
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
10. PROPERTY, PLANT AND EQUIPMENT
FREEHOLD
LAND AND
BUILDINGS
$
PRODUCING
ASSETS
$
ASSETS IN
DEVELOPMENT
$
PLANT AND
EQUIPMENT
$
RESTORATION
ASSET
$
TOTAL
$
Year ended 30 June 2014
Opening net book amount
Additions
Additions – business combinations
Transfer from exploration
Disposals and write offs
Depreciation charge
424,497
—
—
—
—
—
2,953,503
15,859,734
—
—
(7,094)
(513,435)
—
2,405,766
16,013,524
—
—
—
860,803
1,132,084
2,953,036
—
(14,803)
(523,435)
—
107,318
4,201,265
482,535
—
1,285,300
6,598,671
39,027,559
482,535
(14,803)
(69,146)
(1,113,110)
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
Accumulated depreciation
430,947
(13,544)
18,813,237
18,419,290
(513,435)
—
6,023,358
(1,615,673)
4,791,118
(69,146)
48,477,950
(2,211,798)
Net book amount
417,403
18,299,802
18,419,290
4,407,685
4,721,972
46,266,152
Year ended 30 June 2015
Opening net book amount
Additions
Assets classified as held for sale
Transfers/reclassifications
Disposals and write offs
Impairment
Depreciation charge
417,403
260,924
(315,738)
—
—
(100,821)
(844)
18,299,802
—
—
13,936,901
—
(381,089)
(1,047,939)
Closing net book amount
260,924
30,807,675
At 30 June 2015
Cost
Accumulated depreciation
260,924
—
32,750,137
(1,942,462)
Net book amount
260,924
30,807,675
18,419,290
2,249,802
—
(20,669,092)
—
—
—
—
—
—
—
4,407,685
17,864,528
—
6,732,191
—
(4,346,903)
(1,344,347)
4,721,972
470,154
—
—
—
46,266,152
20,845,408
(315,738)
—
—
(692,302)
(304,162)
(5,521,115)
(2,697,292)
23,313,154
4,195,662
58,577,415
30,725,815
5,261,271
68,998,147
(7,412,661)
(1,065,609)
(10,420,732)
23,313,154
4,195,662
58,577,415
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
59
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
11.
EXPLORATION ASSETS
NOTE
2015
$
2014
$
Acquisition costs of right to explore
8,898,767
16,869,693
Movement for the year:
Balance at the beginning of the year
Expenditure incurred during the year
Impairment of exploration assets
Additions – business combinations
Permits reclassified as held for sale
Restoration asset transferred to producing assets
Balance at the end of the year
12.
INTANGIBLE ASSETS
16,869,693
—
(6,570,926)
—
(1,400,000)
16,702,228
—
—
650,000
—
—
(482,535)
8,898,767
16,869,693
9
10
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
274,644
(255,123)
19,521
19,521
2,828
(10,297)
12,052
262,311
(250,259)
12,052
270,373
(241,079)
29,294
29,294
4,271
(14,044)
19,521
274,644
(255,123)
19,521
13. OTHER FINANCIAL ASSETS
Security bonds on exploration permits & rental properties
2,075,733
2,423,185
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.
60
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
14. GOODWILL
2015
$
2014
$
Goodwill arising from business combinations
3,906,270
3,906,270
Impairment tests for goodwill
Goodwill is monitored by management at the level of the operating segments and has been allocated to Gas Producing assets.
There has been no impairment of amounts previously recognised as goodwill. Goodwill is tested for impairment on an annual
basis. The recoverable amount of a Cash Generating Unit (CGU) is determined based on value‐in‐use calculations which require
the use of assumptions. The calculations use cash flow projections based on budgets for the next financial year as approved by
management and forecasts beyond the budget based on extrapolations using estimated growth rates.
Cash flows for revenues are based on contracted gas prices with allowance for CPI increases to prices where applicable.
The following table sets out the key assumptions for the Gas Producing assets value‐in‐use calculations:
2015
Gas Producing Assets
Sales Volumes
Sales Price (% annual growth rate)
Operating costs (annual growth rate)
Pre‐tax discount rate (%)
Contracted
2.50%
2.50%
17.42%
Management has determined the values assigned to each of the above key assumptions as follows:
Assumption
Approach used to determining values
Sales volume
Sales price
Operating costs
Annual minimum contracted quantities (subject to Take or Pay clauses where applicable)
Current contracted prices escalated for CPI increases as per contracts. Some contracts contain
minimum and maximum increases.
Current budgeted operating costs which are based on past performance and expectations for the
future. Forecasts are inflated beyond the budget year using inflationary estimates. Other known
factors are included where applicable and known with certainty
Capital expenditure
Expected cash costs where further field capital expenditure is required in order to meet contracted
sale volumes. No incremental revenue or costs savings are assumed as a result of this expenditure
Long term growth rate
This is the average growth rate used to extrapolate cash flows beyond the budget period.
Management considers forecast inflation rates and industry trends if applicable
Pre‐tax discount rate
This rate reflects risks relating to the segment. Post‐tax discount rates have been applied to
discount the forecast future post‐tax cash flows. The equivalent pre‐tax discount rates are
disclosed in the table above.
15. TRADE AND OTHER PAYABLES
Trade payables
Other payables
Southern Georgina joint arrangement contribution
Accruals
2015
$
2,540,490
558,410
3,676,864
932,133
7,707,897
2014
$
3,893,054
797,713
4,305,514
1,480,027
10,476,308
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.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
61
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
16.
INTEREST BEARING LIABILITIES
(a)
Interest bearing liabilities (current)1
Debt facilities
(b)
Interest bearing liabilities (non‐current)1
Debt facilities
1 Details regarding interest bearing liabilities are contained in Note 31(e).
2015
$
7,921,129
7,921,129
2014
$
255,760
255,760
39,536,722
39,536,722
23,761,593
23,761,593
17. PROVISIONS
Employee entitlements (a)
Onerous contracts (b)
Restoration and rehabilitation (c)
Other
2015
Current Non-current
$
$
1,761,378
298,952
—
—
228,987
392,939
5,753,613
—
2014
Total
$
Current Non-current
$
$
1,990,365
691,891
5,753,613
—
1,105,995
361,774
—
1,248,299
167,376
356,690
4,907,070
—
Total
$
1,273,371
718,464
4,907,070
1,248,299
2,060,330
6,375,539
8,435,869
2,716,068
5,431,136
8,147,204
(a) The current provision for employee entitlements includes accrued short term incentive plans, all accrued annual leave and the
unconditional entitlements to long service leave where employees have completed the required period of service. The amounts
are presented as current, since the consolidated entity does not have an unconditional right to defer settlement for these
obligations. However, based on past experience, the group does not expect all employees to take the full amount of accrued
leave or require payment in the next 12 months. The following amounts reflect leave that is not expected to be taken or paid
within the next 12 months:
2015
$
2014
$
Current leave obligations expected to be settled after 12 months
520,916
479,696
(b) The provision for onerous contracts relates to operating lease commitments on the rental of office space at 167 Eagle Street
Brisbane. The 2014 provision also included office space in Perth for which the lease has since expired.
(c) Provisions for future removal and restoration costs are recognised where there is a present obligation and it is probable that an
outflow of economic benefits will be required to settle the obligation. The estimated future obligations include the costs of
removing facilities, abandoning wells and restoring the affected areas.
62
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
17. PROVISIONS (continued)
Movements in Provisions
Movements in each class of provision during the financial year are set out below:
2015
Carrying amount at start of year
Additional provision charged to
property, plant and equipment
Charged/(credited) to profit or loss
‐ Additional provisions
‐ Unused amounts reversed
‐ Unwinding of discount
Amounts used during the year
Employee
entitlements
$
1,273,371
Onerous
Contracts
$
718,464
Restoration and
Rehabilitation
$
Other
$
Total
$
4,907,070
1,248,299
8,147,204
—
—
470,154
1,291,071
311,216
—
—
(574,077)
—
—
(337,789)
194,828
—
181,561
—
—
—
(194,485)
—
(1,053,814)
470,154
1,797,115
(194,485)
181,561
(1,965,680)
Carrying amount at end of year
1,990,365
691,891
5,753,613
—
8,435,869
18. CONTRIBUTED EQUITY
(a)
Share Capital
368,718,957 (2014: 348,718,957) fully paid ordinary shares
2015
$
2014
$
160,785,182
155,223,040
Ordinary shares have no par value and the company does not have a limited amount of authorised capital.
On a show of hands every holder of ordinary shares present at a meeting in person or by proxy, is entitled to one vote, and upon a poll each share is
entitled to one vote.
(b) Movements in ordinary share capital
Balance at start of year
Placement of shares to institutional investors on
26 July 2013 at 10 cents per share
Placement of shares to institutional investors on
2 October 2014 at 30 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
Share consolidation
Exercise of listed options at 80 cents per share
Exercise of listed options at 45 cents per share
Capital raising costs
2015
2014
No. of shares No. of shares
1,440,078,845
348,718,957
2015
$
2014
$
155,223,040
130,258,022
—
106,000,000
—
10,600,000
20,000,000
—
6,000,000
—
—
—
—
—
39,473,684
(1,236,863,076)
3,904
25,600
—
—
—
—
(437,858)
15,000,000
—
3,123
11,250
(649,355)
368,718,957
348,718,957
160,785,182
155,223,040
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
63
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
18. CONTRIBUTED EQUITY (continued)
(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
17 July 2014
9 April 2015
Unlisted employee options
Unlisted employee options
EXPIRY DATE
15 Nov 2015
15 Nov 2017
EXERCISE
PRICE
NUMBER OF
OPTIONS
40 cents
Various
220,000
5,288,843
(d) Options exercised during the year
The following options over unissued ordinary shares were exercised during the year:
CLASS
Listed options (CTPO)
Unlisted employee options
EXPIRY DATE
EXERCISE
PRICE
NUMBER OF
OPTIONS
—
—
(e) Options lapsed or cancelled during the year
The following options over unissued ordinary shares lapsed during the year:
CLASS
Unlisted employee options
Unlisted employee options
Unlisted employee options
EXPIRY DATE
31 Mar 2015
9 Apr 2015
31 May 2015
EXERCISE
PRICE
NUMBER OF
OPTIONS
$0.625
$0.475
$0.610
13,000,003
450,000
1,268,000
(f) Unissued shares under option
At year end, options over unissued ordinary shares of the Company are as follows:
CLASS
Unlisted options (CTPO)
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
Unlisted employee options
Unlisted employee options
Unlisted employee options
Unlisted employee options
Unlisted employee options
EXPIRY DATE
EXERCISE
PRICE
NUMBER OF
OPTIONS
30 Sep 2016
31 Oct 2015
15 Nov 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 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
$0.500
$0.550
$0.400
$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
$0.400
$0.410
$0.450
$0.475
$0.650
15,000,000
120,000
220,000
9,683,634
4,354,334
1,366,670
207,000
40,000
669,334
400,000
600,000
2,318,668
400,000
24,900,772
2,733,335
1,350,000
782,525
234,000
2,429,068
1,449,350
393,900
None of the options entitle holders to participate in any share issue of the Company or any other entity.
64
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
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 has an undrawn equity line of credit facility of $10 million due to expire 24 September 2016. The facility can be drawn down
in $250,000 amounts, however upon initial draw down cash fees of $200,000 and up to 5 million options would become payable.
19. RESERVES
Share options reserve
Movements:
Balance at start of year
Share based payment costs (a)
Options issued for financing (b)
Balance at end of year
2015
$
2014
$
16,695,379
14,448,695
14,448,696
2,246,683
—
10,132,939
2,818,231
1,497,526
16,695,379
14,448,696
(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.
20. ACCUMULATED LOSSES
Movements in accumulated losses were as follows:
Balance at the start of year
Net loss for the year
Balance at end of year
21.
LOSSES PER SHARE
(a) Basic loss per share (cents)
(b) Diluted loss per share (cents)
(c) Loss used in loss per share calculation
(126,603,023)
(27,731,038)
(115,745,037)
(10,857,986)
(154,334,061)
(126,603,023)
(7.63)
(7.63)
(3.42)
(3.42)
Loss attributed to ordinary equity holders of the Company
(27,731,038)
(10,857,986)
(d) Weighted average number of ordinary shares
Weighted average number of shares used as the denominator
in calculating basic and diluted earnings per share
363,568,272
317,351,393
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 Note 18
for details of options on issue.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
65
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
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.
Gas Producing assets
Production and sale from those fields where the major source of revenue arises from the sale of natural gas.
Oil Producing assets
Production and sale from those fields where the major source of revenue arises from the sale of crude oil.
Development assets
Fields under development in preparation for the sale of petroleum products.
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.
66
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
22. SEGMENT REPORTING (continued)
GAS PRODUCING
ASSETS
2015
$
OIL PRODUCING
ASSETS
2015
$
DEVELOPMENT
ASSETS
2015
$
EXPLORATION
ASSETS
2015
$
Revenue (a)
Cost of sales (b)
Gross profit (c)
Other income
Share based employee benefits
General and administrative expenses
Depreciation and amortisation
Employee benefits and associated
costs
Exploration expenditure
Finance costs (d)
Impairment expense
5,301,806
5,011,460
(4,788,864)
(5,328,174)
512,942
(316,714)
—
—
—
—
—
—
(1,919,747)
(450,915)
—
—
—
—
(3,707,037)
(24,848)
—
(5,420,293)
Loss before income tax
(5,113,842)
(6,212,770)
Taxes
—
—
Profit / (Loss) for the year
(5,113,842)
(6,212,770)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
UNALLOCATED
ITEMS CONSOLIDATION
2015
2015
$
$
—
—
—
10,313,266
(10,117,038)
196,228
7,480,298
7,480,298
(2,246,683)
(2,246,683)
(1,938,425)
(1,938,425)
—
—
—
—
—
—
(24,045)
(312,882)
(2,707,589)
—
(5,018,180)
(5,018,180)
(7,655,931)
—
(7,655,931)
—
(16,829)
(3,748,714)
(6,570,927)
(100,822)
(12,092,042)
(14,250,903)
(2,153,523)
(27,731,038)
—
—
—
(14,250,903)
(2,153,523)
(27,731,038)
Segment assets
63,661,928
1,186,421
—
11,641,829
10,257,939
86,748,117
Segment liabilities
(52,626,015)
(1,786,427)
—
(4,880,467)
(4,308,708)
(63,601,617)
Capital expenditure
Property, plant and equipment
331,351
2,002,241
18,442,116
Total capital expenditure
331,351
2,002,241
18,442,116
8,253
8,253
61,447
20,845,408
61,447
20,845,408
(a) Revenue from the gas producing assets for the year ended 30 June 2015 included a full year of revenues for Palm Valley (2014
only 3 months) however deliveries under the Palm Valley GSA were in ramp‐up mode with full contract quantities delivered
from April 2015. The Dingo pipeline and gas processing facilities were installed ready to deliver under the PWC GSA from 1 April
2015 however sales await the customer’s physical tie‐in to the Dingo delivery point and as such no gas was supplied under the
gas sales contract during the financial year. The contract contains a “Take or Pay” arrangement however this is based on a
calendar and not payable until January in the following year and therefore no revenue has been recognised to 30 June 2015 in
accordance with the accounting policy for revenue recognition (Refer Note 1(e)(i)).
(b) Cost of sales for gas producing assets reflect a full year of operating costs for the Palm Valley gas field. It should be noted,
however, that whilst Palm Valley was in full operational mode all year, gas sales production was in ramp‐up mode under the
Palm Valley GSA with full contract quantities being delivered from April 2015. In addition, although deliveries under the
PWC GSA await the customer’s physical tie‐in to the Dingo delivery point, the field became operational from 1 April 2015 thus
adding to the cost of sales reported for the year.
(c) Gross profit from gas producing assets for the period is masked by the disparity between revenues earned and cost of sales
incurred as explained in (a) and (b) above and therefore does not reflect the gross profit that would otherwise be achieved
from the Palm Valley and Dingo gas fields delivering full annual contract quantities.
(d) Finance Costs totaling $3.55 million relate to the Macquarie debt facility for the acquisition of the Palm Valley and Dingo gas
fields and comprise borrowing costs of $613,000 and interest of $2.94 million (refer Note 31(e) for details on the facility). Of
the total $3.55 million, $1.93 million relates to the Dingo gas field which although development was completed and the
PWC GSA commenced on 1 April 2015 did not earn sales revenue as originally anticipated. The balance of $1.62 million relates
to the Palm Valley gas field which anticipated full contract nominations during the year but did not ramp up revenues until May
2015. The Macquarie facility is secured by the Palm Valley and Dingo gas fields and is serviced by their respective cash flows.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
67
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
22. SEGMENT REPORTING (continued)
GAS PRODUCING
ASSETS
2014
$
OIL PRODUCING
ASSETS
2014
$
DEVELOPMENT
ASSETS
2014
$
EXPLORATION
ASSETS
2014
$
UNALLOCATED
ITEMS
2014
$
Revenue
Cost of sales
Gross profit
Other income
Share based employee benefits
General and administrative expenses
Business combinations transaction
fees
Depreciation and amortisation
Employee benefits and associated
costs
Exploration expenditure
Finance costs
Loss before income tax
Taxes
1,226,407
2,491,695
(897,103)
(2,119,391)
329,304
372,304
—
—
—
—
—
—
—
(119,569)
—
(393,866)
—
—
(1,017,295)
(807,560)
—
—
—
(21,723)
(43,285)
—
Profit / (Loss) for the year
(807,560)
(43,285)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
CONSOLIDATION
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)
—
(1,957)
(1,040,975)
(4,659,886)
(9,454,753)
(14,965,484)
—
4,107,498
4,107,498
(4,659,886)
(5,347,255)
(10,857,986)
Segment assets
Segment liabilities
20,767,460
3,803,319
25,989,302
21,436,107
13,713,390
85,709,578
(2,990,538)
(1,988,483)
(3,575,974)
(5,250,758)
(28,835,112)
(42,640,865)
Capital expenditure
Exploration and evaluation assets
Property, plant and equipment
—
23,192,274
—
3,780,297
—
650,000
—
650,000
18,415,085
—
242,845
45,630,501
Total capital expenditure
23,192,274
3,780,297
18,415,085
650,000
242,845
46,280,501
In 2015 the Group changed its segment reporting to separate oil producing assets from gas producing assets. Consequently the
2014 segment reporting note has been revised to reflect the same reporting format as 2015.
2015
$
2014
$
Revenue from external customers by geographical location of production
Australia
10,313,266
3,718,102
Non‐current assets by geographical location
Australia
73,470,237
69,484,821
Major Customers
Revenue from one customer represents $8,223,782 or 80 percent of the group’s total oil and gas revenues (2014: $2,491,694 or
67 percent of the group’s total oil and gas revenues). No other customers had revenue exceeding 10 percent of the group’s total
oil and gas revenue for the 2015 year.
In 2014 revenue from another customer represented $1,226,408 or 33 percent of the group’s total oil and gas revenues for that
year.
68
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
23. PARENT ENTITY INFORMATION
Summary financial information
(a)
The individual financial summary statements for the parent entity show the following aggregate amounts:
Statement of financial position
Current assets
Non‐current assets
Total assets
Current liabilities
Total liabilities
Net assets
Shareholders’ equity
Issued capital
Reserves
Accumulated losses
Total equity
Loss for the year
Total comprehensive loss
2015
$
2014
$
9,872,277
9,065,573
18,937,850
9,188,446
11,070,840
20,259,286
(3,915,769)
(3,118,556)
(4,308,708)
(4,806,901)
14,629,142
15,452,385
160,785,182
16,695,379
(162,851,419)
155,223,040
14,448,695
(154,219,350)
14,629,142
15,452,385
(8,632,069)
(31,899,516)
(8,632,069)
(31,899,516)
(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.
Contingent assets and liabilities of the parent entity
(c)
There are no contingent asset or liabilities.
(d) Commitments of the parent entity
Operating lease commitments of the parent entity are set out in Note 29(b).
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
69
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
24. RELATED PARTY TRANSACTION
(a) Parent entity
The parent entity is Central Petroleum Limited.
(b) Subsidiaries
The consolidated financial statements include the financial statements of Central Petroleum Limited and the subsidiaries
listed in the following table:
NAME OF ENTITY
Merlin Energy Pty Ltd
Central Petroleum Projects Pty Ltd
(formerly Merlin West Pty Ltd)
Helium Australia Pty Ltd
Ordiv Petroleum Pty Ltd
Frontier Oil & Gas Pty Ltd
Central Green Pty Ltd
Central Geothermal Pty Ltd
Central Petroleum Services Pty Ltd
Central Petroleum PVD Pty Ltd
Central Petroleum (N.T) Pty Ltd
Jarl Pty Ltd
Central Petroleum Mereenie Pty Ltd
Central Petroleum Mereenie Unit Trust
(c) Key management personnel
PLACE OF
INCORPORATION
Western Australia
CLASS OF
SHARES
Ordinary
Western Australia
Victoria
Western Australia
Western Australia
Western Australia
Western Australia
Western Australia
Queensland
Queensland
Queensland
Queensland
N/A
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Ordinary
Units
Disclosures relating to key management personnel are set out in Note 25.
EQUITY HOLDING
2014
2015
%
%
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
—
—
25. KEY MANAGEMENT PERSONNEL
(a) Key management personnel compensation
Short‐term employee benefits
Post‐employee benefits
Long‐term benefits
Share based payments
2015
$
2014
$
3,090,130
210,674
50,439
2,150,273
3,257,142
210,954
40,581
2,268,975
5,501,516
5,777,652
Detailed remuneration disclosures are provided in the remuneration report on pages 22 to 34.
(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 22 to 34.
70
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
25. KEY MANAGEMENT PERSONNEL (continued)
(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
EXERCISABLE
UNVESTED
Non-Executive Directors
Andrew Whittle
William Dunmore3
Wrixon Gasteen
Robert Hubbard
J. Thomas Wilson
Peter Moore
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
900,000
900,000
—
280,000
1,000,000
1,000,000
—
N/A
—
N/A
—
N/A
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Executive Directors and Other Key Management Personnel
Richard Cottee1
Michael Herrington
Daniel White
Bruce Elsholz2
Leon Devaney
Michael Bucknill
Robbert Willink
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
34,584,407
34,584,407
2,700,000
900,000
1,643,334
929,200
1,170,000
600,000
560,000
—
—
—
—
N/A
—
—
—
1,800,000
450,000
733,334
370,500
570,000
504,000
560,000
430,000
—
450,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(280,000)
—
—
—
—
—
—
—
—
—
—
(450,000)
—
(600,000)
(19,200)
(400,000)
—
—
—
—
—
—
—
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
1,140,500
N/A
N/A
N/A
N/A
N/A
N/A
N/A
900,000
900,000
—
—
1,000,000
1,000,000
—
—
—
—
—
—
34,584,407
34,584,407
2,250,000
2,700,000
1,493,334
1,643,334
N/A
1,170,000
1,064,000
560,000
430,000
—
450,000
—
300,000
300,000
—
—
333,334
333,334
—
—
—
—
—
—
9,683,634
9,683,634
300,000
300,000
1,043,334
1,643,334
N/A
1,170,000
560,000
560,000
100,000
—
120,000
—
600,000
600,000
—
—
666,666
666,666
—
—
—
—
—
—
24,900,773
24,900,773
1,950,000
2,400,000
450,000
—
N/A
—
504,000
—
330,000
—
330,000
—
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 interest
2 Bruce Elsholz resigned effective 30 November 2014.
3 William Dunmore and Michael Herrington retired as directors effective 26 November 2014. Michael Herrington remains Chief Operating Officer.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
71
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
25. KEY MANAGEMENT PERSONNEL (continued)
(iii) Deferred shares – long term incentive plan
Under the group’s Employee Rights Plan, eligible employees may receive rights to deferred shares of Central Petroleum Limited.
The rights are granted in respect of a plan year which commences 1 July each year. The share rights remain unvested until the
end of the performance period which is three years commencing from the start of each plan year. Eligible employee must still be
in the employment of Central Petroleum Limited as at the vesting date for the rights to vest.
Final vesting percentages are determined by a combination of performance hurdles in respect of a combination of absolute total
shareholder return and relative total shareholder return compared to a specific group of Exploration and Production companies
as determined by the Board.
The number of rights to be granted to eligible employees is determined based on the maximum long term incentive amount
applicable for each employee, being either a fixed dollar amount or a percentage of the employee’s base salary, divided by the
volume weighted average share price (VWAP) at the start of the plan year.
The maximum number of rights to ordinary shares in the Company under the long term incentive plan held during the financial
year by other key management personnel of the consolidated entity, including their personally related parties, are set out below:
RIGHTS HELD
AT START OF
YEAR
MAXIMUM
NUMBER
GRANTED AS
COMPENSATION
CANCELLED
DURING THE
YEAR
CONVERTED TO
SHARES
RIGHTS HELD
AT END OF
YEAR)
Executive Directors and Other Key Management Personnel
Richard Cottee
Michael Herrington
Daniel White
Leon Devaney
Michael Bucknill
Robbert Willink
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
330,000
—
278,571
—
274,285
—
262,286
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
330,000
—
278,571
—
274,285
—
262,286
—
72
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
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
PURCHASE
RECEIVED ON
EXERCISE OF
OPTIONS
NET CHANGE
OTHER
HELD AT
DATE OF
DEPARTURE
HELD AT
END OF YEAR
Non-Executive Directors
Andrew Whittle
William Dunmore1
Wrixon Gasteen
Robert Hubbard
J. Thomas Wilson
Peter Moore
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
133,680
133,680
183,743
183,743
97,000
104,000
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
102,364
—
—
—
—
—
55,900
64,100
—
—
—
—
Executive Directors and Other Key Management Personnel
Richard Cottee
Michael Herrington1
Daniel White
Bruce Elsholz2
Leon Devaney
Michael Bucknill
Robbert Willink
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
208,683
208,683
200,000
200,000
288,000
288,000
—
—
110,000
110,000
31,000
—
—
—
1 Retired, as Directors effective 26 November 2014
2 Resigned 30 November 2014
N/A
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
227,700
—
50,000
—
—
—
—
—
100,000
—
25,000
—
—
—
(c) Other transactions with key management personnel
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(7,000)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
N/A
N/A
183,743
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
236,044
133,680
N/A
183,743
97,000
97,000
120,000
64,100
—
—
—
—
436,383
208,683
250,000
200,000
288,000
288,000
N/A
—
210,000
110,000
56,000
31,000
—
—
(i) During the year ended 30 June 2015 the consolidated entity paid $29,594 (2014: $24,476) 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) Prior to 26 June 2015 FEP 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 33. Richard Cottee has a
50 percent beneficial equity interest in FEP.
During the year ended 30 June 2015 FEP has received compensation of $518,783 (2014: $516,470).
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
73
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
26. RECONCILIATION OF LOSS AFTER INCOME TAX TO NET CASH
OUTFLOW FROM OPERATING ACTIVITIES
Loss after income tax
Adjustments for:
Depreciation and amortisation
Share‐based payments
Income tax expense
Impairment expense
Borrowing expenses (non‐cash)
Write off exploration expenditure
Changes in assets and liabilities relating to operating activities:
(Increase)/Decrease in trade and other receivables
(Increase) in inventories
Decrease/(Increase) in exploration assets
Increase in trade and other payables
(Decrease)/Increase in provisions
2015
$
2014
$
(27,731,038)
(10,857,986)
2,707,589
2,246,683
—
12,092,042
3,461,743
194,913
(2,920,023)
(195,691)
—
101,327
(557,878)
1,127,155
2,818,231
(4,107,498)
—
—
—
3,981,516
(965,702)
(650,000)
7,847,852
1,284,193
(10,600,333)
477,761
27. NON CASH INVESTING AND FINANCING ACTIVITIES
In 2014 the consolidated entity purchased 100 percent 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.
28. CONTINGENCIES
(a) Contingent liabilities
(i)
The consolidated entity had contingent liabilities at 30 June 2015 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 (2014: $1,000,000) within twelve months following the commencement of any future
commercial production from the permits.
(ii) 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 percent 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 Northern Territory gas
market conditions, we do not anticipate paying a gas price bonus over the relevant term and have therefore ascribed a $nil
value to this contingent liability. Should access to 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.
(b) Contingent assets
There were no contingent assets at 30 June 2015 (30 June 2014 ‐ $NIL).
74
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
29. COMMITMENTS
2015
$
2014
$
(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
(i)
5,516,898
15,500,000
8,000,000
32,976,497
15,447,000
24,000,000
29,016,898
72,423,497
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.
(i) 2014: $21,346,497 of this commitment relates to the Dingo gas field development funded by the Macquarie debt facility.
(b) Operating lease commitments
The consolidated entity, through its parent entity Central Petroleum Limited, has non‐cancellable operating leases for office
premises and accommodation in Alice Springs and Brisbane. The leases have varying terms, escalation clauses and renewal rights.
Commitments for minimum lease payments in relation to non‐cancellable operating leases are payable as follows:
Within one year
Later than one year but not later than five years
757,316
1,483,533
2,240,849
595,987
2,414,894
3,010,881
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
75
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
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.
EXPIRY DATE
EXERCISE
PRICE1
BALANCE AT
START OF
THE YEAR
GRANTED
DURING THE
YEAR
EXERCISED
DURING THE
YEAR
EXPIRED OR
FORFEITED
DURING THE
YEAR
BALANCE AT
END OF THE
YEAR
VESTED AND
EXERCISABLE
AT THE END
OF THE YEAR
No.
No.
No.
No.
No.
$
2015
31 May 2015
31 Oct 2015
15 Nov 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 Nov2016
30 Nov 2016
$0.610
$0.550
$0.400
$0.450
$0.450
$0.450
$0.650
$0.600
$0.550
$0.575
$0.575
$0.475
$0.475
1,268,000
120,000
—
—
—
220,000
9,683,634
4,354,334
1,366,670
207,000
40,000
669,334
400,000
600,000
2,318,668
400,000
2,733,335
—
—
—
—
—
—
—
—
—
—
—
—
—
120,000
220,000
—
120,000
220,000
9,683,634
9,683,634
4,354,334
4,354,334
1,366,670
1,366,670
207,000
40,000
669,334
400,000
600,000
207,000
40,000
669,334
400,000
600,000
2,318,668
2,318,668
400,000
400,000
(1,268,000)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
15 Nov 2017
$0.450
24,900,773
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
$0.450
$0.475
$0.450
$0.400
$0.410
$0.650
1,800,000
1,449,350
—
—
—
—
2,429,068
782,525
234,000
393,900
24,900,773
2,733,335
(450,000)
2,799,350
—
—
—
—
2,429,068
782,525
234,000
393,900
—
—
—
—
—
—
—
Totals
50,861,748
5,508,843
—
(1,718,000)
54,652,591
20,379,640
Weighted average exercise price
$0.46
$0.44
$0.57
$0.46
$0.46
Weighted average remaining contractual life (years) at the end of the year
1.71
1 On 27 September 2013 shareholders approved every 5 ordinary shares held be converted into 1 ordinary share (subject to rounding).
76
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
30. SHARE BASED PAYMENTS (continued)
(a) Employee options (continued)
EXERCISE
PRICE1
BALANCE AT
START OF
THE YEAR
GRANTED
DURING THE
YEAR
EXERCISED
DURING THE
YEAR
EXPIRED OR
FORFEITED
DURING THE
YEAR
BALANCE AT
END OF THE
YEAR
VESTED AND
EXERCISABLE
AT THE END
OF THE YEAR
No.
No.
No.
No.
No.
$
EXPIRY DATE
2014
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
15 Nov 2015
15 Nov 2015
12 May 2016
20 Jul 2016
19 Aug 2016
30 Aug 2016
15 Nov2016
30 Nov 2016
15 Nov 2017
15 Nov 2017
15 Nov 2017
$1.110
$1.250
$1.400
$1.600
$1.850
$1.000
$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
$0.475
300,000
300,000
300,000
300,000
300,000
1,673,334
1,268,000
120,000
9,683,634
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
4,379,334
(25,000)
1,366,670
—
—
207,000
40,000
669,334
400,000
800,000
2,318,668
400,000
2,733,335
—
—
—
—
—
—
—
—
$0.450
24,900,773
—
1,800,000
(300,000)
(300,000)
(300,000)
(300,000)
(300,000)
(1,673,334)
—
—
—
—
—
—
—
—
—
(200,000)
—
—
—
—
—
—
—
—
—
—
—
N/A
N/A
N/A
N/A
N/A
N/A
1,268,000
1,268,000
120,000
120,000
9,683,634
9,683,634
4,354,334
4,354,334
1,366,670
1,366,670
207,000
40,000
669,334
400,000
600,000
—
40,000
669,334
400,000
600,000
2,318,668
2,318,668
400,000
400,000
24,900,773
2,733,335
1,800,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Totals
47,873,748
6,386,334
(25,000)
(3,373,334)
50,861,748
21,220,640
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
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
77
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
30. SHARE BASED PAYMENTS (continued)
(b) Employee options granted during the year
GRANT DATE EXPIRY DATE
2015
NUMBER OF
OPTIONS
AVERAGE
FAIR VALUE
PER OPTION
EXERCISE
PRICE
PRICE OF
SHARES ON
GRANT DATE
ESTIMATED
VOLATILITY*
RISK FREE
INTEREST
RATE
DIVIDEND
YIELD
17 Jul 2014
15 Nov 2015
220,000
9 Apr 2015
9 Apr 2015
9 Apr 2015
9 Apr 2015
9 Apr 2015
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
15 Nov 2017
1,449,350
2,429,068
782,525
234,000
393,900
2014
10 Jul 2013
15 Nov 2015
4,379,334
28 Nov 2013
15 Nov 2017
1,800,000
10 Apr 2014
15 Nov 2015
207,000
$0.020
$0.059
$0.062
$0.067
$0.066
$0.043
$0.047
$0.045
$0.055
$0.400
$0.475
$0.450
$0.400
$0.410
$0.650
$0.450
$0.475
$0.650
$0.375
$0.125
$0.125
$0.125
$0.125
$0.125
$0.625
$0.320
$0.490
45% to 65%
55% to 75%
55% to 75%
55% to 75%
55% to 75%
55% to 75%
60% to 90%
45% to 65%
45% to 65%
2.79%
1.74%
1.74%
1.74%
1.74%
1.74%
2.73%
2.69%
2.79%
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.
(c) Deferred shares – Long Term Incentive Plan
Under the group’s Employee Rights Plan, eligible employees may receive rights to deferred shares of Central Petroleum Limited.
The rights are granted in respect of a plan year which commences 1 July each year. The share rights remain unvested until the end
of the performance period which is three years commencing from the start of each plan year. Eligible employee must still be in the
employment of Central Petroleum Limited as at the vesting date for the rights to vest.
Final vesting percentages are determined by a combination of performance hurdles in respect of a combination of absolute total
shareholder return and relative total shareholder return compared to a specific group of Exploration & Production companies as
determined by the Board.
The number of rights to be granted to eligible employees is determined based on the maximum long term incentive amount
applicable for each employee, being either a fixed dollar amount or a percentage of the employee’s base salary, divided by the
volume weighted average share price (VWAP) at the start of the plan year.
Invitation letters for the plan year commencing 1 July 2014 were issued to eligible employees on 17 June 2015.
Maximum number of rights expected to be granted to employees
Fair value of rights (per right)
2015
2014
2,811,401
$0.074
—
—
(d) Expenses arising from share‐based payment transactions
Total expenses arising from share‐based transactions recognised during the year were:
Options and rights issued to directors and employees
2,246,683
2,818,231
2015
$
2014
$
78
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
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 large customers where the credit risk is considered minimal.
The aging of the consolidated entity’s receivables at reporting date was:
TRADE AND OTHER
RECEIVABLES
Past due: 0‐30 days
Past due: 31‐150 days
Past due: 151‐365 days
GROSS
IMPAIRMENT
2015
$
4,746,959
481,536
—
2014
$
1,191,514
1,274,539
—
5,228,495
2,466,053
2015
$
2014
$
—
—
—
—
—
—
—
—
Based on historic default rates, the consolidated entity believes that no impairment allowance is necessary in respect of receivables
past due over 30 days.
The receivables at 30 June 2015 relate predominantly to the oil sales from Surprise West field and gas sales from the Palm Valley
field. In addition amounts receivable exist from joint arrangement partner recharges and GST refunds due from the Australian tax
office. 100 percent of trade and other receivables have been received to date.
Credit risk also arises in relation to financial guarantees given to certain parties (see Note 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:
2015
Financial Assets
Cash and cash equivalents
Trade and other receivables
Other financial assets
Financial Liabilities
Trade and other payables
Interest bearing liabilities
≤ 6 MONTHS 6–12 MONTHS
1–5 YEARS
≥ 5 YEARS
TOTAL
3,516,139
5,228,495
—
8,744,634
(7,707,897)
(1,345,761)
—
—
—
—
—
—
—
2,075,733
2,075,733
—
(6,575,368)
(39,536,722)
(9,053,658)
(6,575,368)
(39,536,722)
—
—
—
—
—
—
—
3,516,139
5,228,495
2,075,733
10,820,367
(7,707,897)
(47,457,851)
(55,165,748)
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
79
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
31.
FINANCIAL RISK MANAGEMENT (continued)
≤ 6 MONTHS
6–12 MONTHS
1–5 YEARS
≥ 5 YEARS
TOTAL
2014
Financial Assets
Cash and cash equivalents
Trade and other receivables
Other financial assets
10,330,474
2,466,053
—
12,796,527
Financial Liabilities
Trade and other payables
(10,476,308)
Macquarie debt facility
—
(255,760)
(23,761,593)
(10,476,308)
(255,760)
(23,761,593)
—
—
—
—
—
—
—
2,423,185
2,423,185
—
—
—
—
—
—
—
—
10,330,474
2,466,053
2,423,185
15,219,712
(10,476,308)
(24,017,353)
(34,493,661)
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:
2015
$
2014
$
Macquarie debt facility (floating rate)
31(e)
2,692,152
24,426,000
Interest Rate Risk
(c)
The consolidated entity’s exposure to interest rate risk, which is the risk that a financial instrument’s value will fluctuate as a result
of changes in market interest rates and the effective weighted average interest rates on classes of financial assets and financial
liabilities, is as follows:
WEIGHTED
AVERAGE
EFFECTIVE
INTEREST RATE
FLOATING
INTEREST RATE
FIXED INTEREST
NON-BEARING
INTEREST
TOTAL
2015
2014
2015
2014
2015
2014
2015
2014
2015
2014
%
%
$
$
$
$
$
$
$
$
Financial Assets:
Cash and cash equivalents
1.2
0.9
3,516,139 10,330,474
Trade and other receivables —
—
Other financial assets
0.7
0.6
—
—
—
—
—
—
—
—
—
—
3,516,139 10,330,474
5,228,495
2,466,053
5,228,495
2,466,053
858,391
485,828
1,217,342
1,937,357
2,075,733
2,423,185
3,516,139 10,330,474
858,391
485,828
6,445,837
4,403,410 10,820,367 15,219,712
Financial Liabilities:
Trade and other payables
—
—
—
Interest bearing liabilities
10.4
10.2
(47,457,851) (24,017,353)
(47,457,851) (24,017,353)
—
—
—
—
—
—
(7,707,897)
(10,476,308) (7,707,897) (10,476,308)
—
— (47,457,851) (24,017,353)
(7,707,897)
(10,476,308) (55,165,748) (34,493,661)
Net Financial Assets /
(Liabilities)
10.4
10.2
(43,941,712) (13,686,879)
858,391
485,828
(1,262,060)
(6,072,898) (44,345,381) (19,273,949)
80
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
31.
FINANCIAL RISK MANAGEMENT (continued)
Interest Rate Sensitivity
A sensitivity of 10 percent has been selected as this is considered reasonable given the current level of both short term and long
term interest rates. A 10 percent 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 2014.
PROFIT OR LOSS
EQUITY
10% Increase
10% Decrease
10% Increase
10% Decrease
2015
Cash and cash equivalents
Interest bearing liabilities
2014
Cash and cash equivalents
Interest bearing liabilities
4,900
492,186
15,456
255,779
(4,900)
(492,186)
(15,456)
(255,779)
—
—
—
—
—
—
—
—
(d) Commodity Risk
The consolidated entity is exposed to commodity price fluctuations in respect of crude oil sales. The consolidated entity does not
hedge crude oil sales. Gas sales are made under long term contracts and as such do not contain any commodity risk.
(e) 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 three tranches totaling $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 Limited 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.
2.
The Group Current Ratio is at least 1:1, excluding amounts payable under the Macquarie debt facility and outstanding
contributions to the Southern Georgina joint arrangement.
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. Refer Note 33(ii) for post balance
date events relating to the Macquarie debt facility.
(f) Currency Risk
The consolidated entity’s exposure to currency risk is limited due to its ongoing operations being in Australia and all associated
contracts completed in Australian dollars. A 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.
(g) Fair Values
The carrying amounts of cash, cash equivalents, financial assets and financial liabilities, approximate their fair values.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
81
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
32.
INTEREST IN JOINT ARRANGEMENTS
Details of joint arrangements in which the consolidated entity has an interest are as follows:
EP 82 (Santos)
EP 105 (Santos)
EP 106 (Santos)
EP 107 (Santos)
EP 112 (Santos)
EP 125 (Santos)
RL 3 & RL 4 (Santos)
EP 115 North Mereenie Block (Santos)
ATP 909 (Total)
ATP 911 (Total)
ATP 912 (Total)
EP(A) 147 (Santos)
Total = TOTAL GLNG Australia
Santos = Santos QNT Pty Ltd
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
2015
%
60.00
60.00
60.00
N/A*
60.00
30.00
N/A*
60.00
90.00
90.00
90.00
N/A*
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
*No longer a joint arrangement. The consolidated entity now has a 100% interest in the Permit
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.
The share in the assets and liabilities of the joint arrangements where less than 100 percent 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:
2015
$
2014
$
Current assets
Cash and cash equivalents
Trade and other receivables
Inventory
Total current assets
Non‐current assets
Property, plant and equipment
Other financial assets
Total non‐current assets
Current liabilities
Trade and other payables
Joint Venture under contributions*
Accruals
Total current liabilities
Non‐Current liabilities
Restoration provision
Total non‐current liabilities
Net liabilities
Joint arrangement contribution to loss before tax
Revenue
Expenses
Profit / (Loss) before income tax
12,330
13,471
387,625
413,426
161,108
7,200
168,308
308,743
3,676,864
109,423
4,095,030
194,829
194,829
3,708,125
9,986
(6,257,000)
(6,247,014)
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
—
—
3,294,518
11,112
(2,948,314)
(2,937,202)
* The Group is liable for the last 20% of the Stage 1 expenditure in the Southern Georgina Joint Venture, with Total funding the first 80%.
82
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED 30 JUNE 2015
33. EVENTS OCCURRING AFTER THE REPORTING PERIOD
Subsequent to 30 June 2015 the following events have occurred:
(i)
Acquisition of Fifty Percent (50%) Interest in Mereenie Oil and Gas Field
On 1 September 2015 the consolidated entity acquired a 50 percent interest in the Mereenie oil and gas field in the Amadeus Basin, Northern
Territory from the Santos group. The Company assumed operatorship of the field effective from that date. A new joint venture will be
established.
The financial effects of this transaction have not been recognised at 30 June 2015 and the acquisition will be included in consolidated results
from 1 September 2015.
PURCHASE CONSIDERATION
Cash paid
Deferred consideration
Free carry of Santos’ share of field appraisal and development
Total purchase consideration
$
35,000,000
10,000,000
5,000,000
50,000,000
As part of the transaction the parties have agreed to a range of matters relating to other Southern Amadeus Basin exploration arrangements
between the parties. The fair values of the assets and liabilities as at the date of acquisition are yet to be determined.
Contingent Consideration
Potential consideration as indicated above is payable if a final investment decision is made on the North East Gas Interconnector (NEGI)
and the Mereenie Joint Venture participants (or their related parties) enter into a gas transportation agreement with the NEGI project
owner within 3 years of the execution date.
The potential consideration comprises a $15 million payment and $55‐75 million of sole funding work to prove up 15 PJ per annum over
10 years in excess of contracted gas for the purposes of transportation via the NEGI. A bullet payment of 50 percent of the remaining
balance of the target of $65 million is payable if the required NEGI works are not completed within 3 years of the pre‐conditions being
satisfied.
The potential undiscounted amount of all future payments that the consolidated entity could be required to make under this
arrangement is between $0 and $47,500,000.
(ii)
Debt facility
As part of the Mereenie acquisition, the Macquarie debt facility has been expanded to include a new Facility “D” of $40 million taking
the total facility limit to $90 million with a final maturity date of 30 September 2020.
The existing repayment schedule has been replaced with a new repayment schedule. Commencing 31 December 2015 the principal
repayment (excluding interest accruing under the facility) is a set amount of $1 million per quarter payable at the end of each calendar
quarter with the balance of the facility due on the final maturity date.
Financial covenants under the revised facility:
Current Ratio is at least 1:1
•
Proved Developed Producing (PDP) Reserves Cover Ratio is greater than 1.3:1
•
Trade creditors ageing over 90 days past the due date must not exceed $5 million.
•
(iii)
Legal Matter
Central Petroleum Limited has been allegedly served with litigation filed in the District Court of Harris County Texas, located in Houston,
Texas, in respect of a farm‐in deal negotiated between the Perth office of Total and Central Petroleum when it was headquartered in
Perth. Central Petroleum is disputing the Court’s jurisdiction. Separately, internal investigations have concluded that there is no factual
basis for the alleged claim and the consolidated entity accordingly denies any liability. The action will be vigorously defended.
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
83
DIRECTORS’ DECLARATION
In the directors’ opinion:
a)
the financial statements and notes set out on pages 38 to 83 of the Consolidated Entity are in accordance with the Corporations Act
2001 (Cth), including:
(i)
(ii)
complying with Accounting Standards, the Corporations Regulations 2001 (Cth) and other mandatory professional reporting
requirements, and
giving a true and fair view of the Consolidated Entity’s financial position as at 30 June 2015 and of its performance for the financial
year ended on that date;
b)
there are reasonable grounds to believe that the company will be able to pay its debts as and when they become due and payable; and
c)
the financial statements comply with the International Financial Reporting Standards as issued by the International Accounting
Standards Board as disclosed in Note 1(a).
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 2015.
This declaration is made in accordance with a resolution of the directors of Central Petroleum Limited:
Richard Cottee
Managing Director
Brisbane
23 September 2015
84
2015 ANNUAL REPORT CENTRAL PETROLEUM LIMITED
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 2015, the consolidated
statement of profit or loss and other 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.
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.
85
Auditor’s opinion
In our opinion:
(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
2015 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.
Material uncertainty regarding continuation as a going concern
Without modifying our opinion, we draw attention to Note 1 in the financial report, which indicates
that, consistent with the development nature of the consolidated entity's activities it has experienced
operating losses, negative cash flows and that current liabilities exceed current assets. Over the next 12
months additional funds will be required to be raised to fund future operations of the consolidated
entity and the Mereenie acquisition commitments. These conditions, along with other matters set forth
in Note 1, indicate the existence of a material uncertainty that may cause significant doubt about the
consolidated entity’s ability to continue as a going concern and therefore, the consolidated entity may
be unable to realise its assets and discharge its liabilities in the normal course of business and at the
amounts stated in the financial report.
Report on the Remuneration Report
We have audited the remuneration report included in pages 26 to 38 of the directors’ report for the
year ended 30 June 2015. 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 2015
complies with section 300A of the Corporations Act 2001.
PricewaterhouseCoopers
Michael Shewan
Partner
Brisbane
23 September 2015
86
ASX ADDITIONAL INFORMATION
DETAILS OF QUOTED SECURITIES AS AT 16 SEPTEMBER 2015:
Top holders
The 20 largest registered holders of the quoted securities as at 16 September 2015 were:
NO. OF
SHARES
32,645,554
13,296,436
10,000,000
4,000,000
3,608,873
3,000,000
2,754,473
2,655,496
2,500,000
2,438,957
2,046,546
1,800,000
1,746,500
1,736,075
1,400,001
1,250,000
1,200,000
1,178,000
1,100,000
1,098,546
%
8.85
3.61
2.71
1.08
0.98
0.81
0.73
0.72
0.68
0.66
0.56
0.49
0.47
0.47
0.38
0.34
0.33
0.32
0.30
0.30
91,455,457
24.80
NAME
Magellan Petroleum Australia Pty Ltd
Citicorp Nominees Pty Limited
Macquarie Bank Limited
Mr Gerard Pieter Tom Van Brugge
National Nominees Limited
Mr Mark Philip Shawcross
J P Morgan Nominees Australia Limited
HSBC Custody Nominees Australia Limited
Mr James Donald Bruce Cochrane + Mrs Joan Elizabeth Cochrane
UBS Nominees Pty Ltd
Franze Holdings Pty Ltd
RBJ Nominees Pty Ltd
John Cresswell Leigh + Dulcie Lynette Leigh
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12
13.
14. Mr Geoffrey Rol
15. Mr Stuart Francis Howes
16.
17.
Edwin Holdings Pty Ltd
Chembank Pty Limited
18. Mr Seager Rex Harbour
19.
20.
Garmi Holdings Pty Ltd
Franze Holdings Pty Limited
DISTRIBUTION SCHEDULE
The distribution schedule of the ordinary fully paid shares as at 16 September 2015 was:
RANGE
1 ‐ 1,000
1,001 ‐5,000
5,001 ‐ 10,000
10,001 ‐ 100,000
100,001 ‐ Over
HOLDERS
915
2,723
1,480
3,165
UNITS
480,472
7,552,913
11,764,061
111,508,405
566
237,413,106
%
0.13
2.05
3.19
30.24
64.39
Total
8,849
368,718,957
100.00
GEOGRAPHIC BREAKDOWN
The geographic distribution schedule of the ordinary fully paid shares as at 16 September 2015 was:
LOCATION
HOLDERS
UNITS
8,592
257
355,073,889
13,645,068
%
96.30
3.70
Australia
Overseas
Total
8,849
368,718,957
100.00
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
87
ASX ADDITIONAL INFORMATION
SUBSTANTIAL SHAREHOLDERS
NAME
NO. OF SHARES
%
Magellan Petroleum Australia Pty Ltd
32,645,554
8.85
UNMARKETABLE PARCELS
Holdings less than a marketable parcel of ordinary shares (being 1,493 shares as at 16 September 2015):
HOLDERS
UNITS
3,387
6,791,328
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.
88
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
INTERESTS IN PETROLEUM PERMITS AND PIPELINE LICENCES
Permits and Licences Granted
TENEMENT
LOCATION
OPERATOR
CTP CONSOLIDATED ENTITY
Beneficial
Registered
Interest (%)
Interest (%)
OTHER JV PARTICIPANTS
Participant
Name
Beneficial
Interest (%)
EP 82 (excl. EP 82 Sub‐Blocks)*
EP 82 Sub‐Blocks**
EP 93
EP 97
EP 105*
EP 106*
EP 107**
EP 112*
EP 115 (excl. EP 115NMB)
EP 115NMB (North Mereenie Block)
EP 125
OL 3 (Palm Valley)
OL 4 (Mereenie)**
OL 5 (Mereenie)**
L 6 (Surprise)
L 7 (Dingo)
RL 3 (Ooraminna)
RL 4 (Ooraminna)
ATP 909*
ATP 911*
ATP 912*
Amadeus Basin NT
Amadeus Basin NT
Pedirka Basin NT
Pedirka Basin NT
Amadeus/Pedirka Basin NT
Amadeus Basin NT
Amadeus/Pedirka Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
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
Permits and Licences under Application
Santos
Central
Central
Central
Santos
Santos
Santos
Santos
Central
Santos
Santos
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
60
60
100
100
60
60
60
60
100
60
30
100
0***
0***
100
100
100
100
90
90
90
60
100
100
100
60
60
100
60
100
60
30
100
50
50
100
100
100
100
90
90
90
Santos
Santos
Santos
Santos
Santos
Santos
Santos
Santos
Total
Total
Total
40
40
40
40
40
70
50
50
10
10
10
TENEMENT
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
LOCATION
Wiso Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Wiso Basin NT
Pedirka Basin NT
Pedirka Basin NT
Georgina Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Amadeus Basin NT
Wiso Basin NT
Wiso Basin NT
Pedirka Basin SA
CTP CONSOLIDATED ENTITY
Registered
Interest (%)
Beneficial
Interest (%)
OTHER JV PARTICIPANTS
Beneficial
Interest (%)
Participant
Name
OPERATOR
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
Central
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
Pipeline Licences
PIPELINE LICENCE
PL 2
PL 30
LOCATION
Amadeus Basin NT
Amadeus Basin NT
OPERATOR
Central
Central
CTP CONSOLIDATED ENTITY
Registered
Interest (%)
Beneficial
Interest (%)
OTHER JV PARTICIPANTS
Beneficial
Interest (%)
Participant
Name
0***
100
50
100
Santos
50
* 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.
** In line with the Company’s announcement of 4 June 2015, Central has entered into an agreement to purchase 50% of OL 4 / OL 5 (Mereenie oil and gas field) and PL 2 (Mereenie
Alice Springs Pipeline) and have granted Santos the right to acquire a 50% interest in EPA 111 and EPA 124, which was completed 1 September 2015. 100% of EP 82 Sub‐Blocks, EP 107
and EPA 147 were returned to Central on execution of this agreement on 3 June 2015.
*** 50% on registration.
CENTRAL PETROLEUM LIMITED 2015 ANNUAL REPORT
89