Cue Energy Resources Limited ABN 45 066 383 971
ANNUAL REPORT
2 0 2 2
General Legal Disclaimer
Various statements in this document may constitute statements relating to intentions, opinion, expectations, present and future operations, possible future events and future financial
prospects. Such statements are not statements of fact, and are generally classified as forward looking statements that involve unknown risks, expectations, uncertainties, variables,
changes and other important factors that could cause those future matters to differ from the way or manner in which they are expressly or impliedly portrayed in this document. Some
of the more important of these risks, expectations, uncertainties, variables, changes and other factors are pricing and production levels from the properties in which the Company has
interests, or will acquire interests, and the extent of the recoverable reserves at those properties. In addition, exploration for oil and gas is expensive, speculative and subject to a wide
range of risks. Individual investors should consider these matters in light of their personal circumstances (including financial and taxation affairs) and seek professional advice from their
accountant, lawyer or other professional adviser as to the suitability for them of an investment in the Company.
Except as required by applicable law or the ASX Listing Rules, the Company does not make any representation or warranty, express or implied, as to the fairness, accuracy,
completeness, correctness, likelihood of achievement or reasonableness of the information contained in this document, and disclaims any obligation or undertaking to publicly update
any forward-looking statement or future financial prospects resulting from future events or new information. To the maximum extent permitted by law, none of the Company or its agents,
directors, officers, employees, advisors and consultants, nor any other person, accepts any liability, including, without limitation, any liability arising out of fault or negligence for any loss
arising from the use of the information contained in this document.
Reference to “CUE” or “the Company” may be references to Cue Energy Resources Limited or its applicable subsidiaries.
CONTENTS
ABOUT US
Cue Energy Resources Limited is an oil and gas production and exploration
company with production assets in Australia, Indonesia and New Zealand.
Offices are located in Melbourne, Australia and Jakarta, Indonesia.
Chairman’s Overview
Corporate Directory
Operations and Financial Review
Reserves and Resources
Sustainability
Taskforce on Climate-related Financial Disclosures
(TCFD) Statement
Directors’ Report
Auditor’s Independence Declaration
Statement of Profit or Loss
And Other Comprehensive Income
Statement of Financial Position
Statement of Changes in Equity
Statement of Cash Flows
Notes to the Financial Statements
Independent Auditor’s Report to the Members
of Cue Energy Resources Limited
Additional Shareholder Information
F Y 22
HI GHLI GHTS
REVENUE
98%
$44.4 million
PROFIT AFTER TAX
226%
$16.1 million
EBITDAX
179%
$29.0 million
PRODUCTION
>600,000 boe
59%
2
4
5
12
16
18
27
43
44
45
46
47
48
81
87
1
CHAIRMAN’S OVERVIEW
30 JUNE 2022
Dear Shareholders,
I am pleased to present the 2022 Annual Report for Cue Energy Limited (ASX: CUE) as we reflect on our achievements
over the past 12 months, a year in which we saw significant growth in both revenues and after tax profits.
During the year, global events highlighted the critical part that our products play in providing energy to the world.
There have been significant changes in the oil and gas markets as a result of the conflict in Ukraine and the lingering
effects of COVID. This has resulted in strong prices for our products which we expect to continue in the short term.
Our strong results in FY22 included $16.1 million profit after tax, a 226% improvement on the previous year. We
achieved a 59% increase in production to more than 600,000 barrels of oil equivalent (boe) and revenues of $44.4
million, up 98% on our FY21 results, our highest annual revenue in more than five years. We also posted $29.0 million
EBITDAX, which is an increase of 179% on the previous year.
This impressive performance across all key metrics was not an anomaly. It reflects the results of our targeted growth
strategy, through development drilling at our existing permits and through acquisitions.
We achieved increased production at the PB Field in the Mahato PSC in Indonesia, with five new production wells
coming on line during FY22. The field achieved a production rate of more than 5,000 barrels of oil per day (bopd).
The Mahato PSC contributed $14.9 million in revenue, five times our revenue from the field in FY21. Also in Indonesia,
Oyong and Wortel fields in the Sampang PSC contributed strongly to our results, generating $12.1 million in revenue.
Our investment onshore Australia via the Amadeus Basin gas assets in the Northern Territory was also an important
contributor to our results. We acquired interests in the Mereenie, Palm Valley and Dingo fields in October 2021, with
the goal of increasing our production portfolio and providing an entry into Australia’s east coast gas market, which
is experiencing strong demand and prices. This investment is already starting to bear fruit , with the Amadeus Basin
assets generating $8.2 million revenue over the three quarters following the acquisition.
Performance at New Zealand’s Maari field improved in FY22, generating $9.2 million revenue, which was a 32%
increase on the previous year.
Building on this performance, we believe FY23 will also be a year of continued growth. We have planned development
projects in three of our permits, all of which will be funded from existing cashflow and cash reserves. We expect
another 10 wells to be drilled in the PB Field over the coming year, at a rate of one well per month. The first two wells,
PB-17 and PB-18, commenced production at good rates, which bodes well for future development success, as similar
rates from additional wells has the potential to increase PB Field oil production by 100% in FY23.
Although our Paus Biru development has been delayed by approvals for longer than we would have liked, the
Sampang joint venture expects to move ahead with a final Investment decision in the first half of this financial year.
First gas from the field, and a new revenue source for Cue, is expected by the start of 2025.
At the Mereenie field there are plans for two infill wells and six well recompletions over the next year. This will increase
near term gas production to existing customers and the east coast market, which remains a high demand, high priced
market. This sets the scene for an extremely busy year ahead for Cue and our operating partners.
I thank our Shareholders for your continued support and I also thank our staff in both Melbourne and Jakarta, led by
our Chief Executive Officer Matthew Boyall, for their hard work throughout the year.
As we continue to scale up our business we are excited by the opportunities in front of us and look forward to a
successful FY23.
Alastair McGregor
Chairman
2
3
CORPORATE DIRECTORY
30 JUNE 2022
DIRECTORS
Alastair McGregor
(Non-Executive Chairman)
Andrew Jefferies
Peter Hood AO
Richard Malcolm
Rod Ritchie
Samuel Kellner
Marco Argentieri
(Non-Executive Director)
(Non-Executive Director)
(Non-Executive Director)
(Non-Executive Director)
(Non-Executive Director)
(Non-Executive Director)
CHIEF EXECUTIVE OFFICER
Matthew Boyall
CHIEF FINANCIAL OFFICER
AND COMPANY SECRETARY
Melanie Leydin
REGISTERED OFFICE
PRINCIPAL PLACE OF
BUSINESS
SHARE REGISTER
AUDITOR
Level 3, 10-16 Queen Street
Melbourne, VIC 3000, Australia
Telephone:
Fax:
+61 3 8610 4000
+61 3 9614 2142
Level 3, 10-16 Queen Street
Melbourne, VIC 3000, Australia
Telephone:
Fax:
+61 3 8610 4000
+61 3 9614 2142
Computershare Investor Services Pty Limited
Yarra Falls, 452 Johnston Street
Abbotsford, VIC 3067, Australia
Telephone:
Fax:
+61 3 9415 5000
+61 3 9473 2500
KPMG
Level 36, Tower Two, Collins Square
727 Collins Street
Melbourne, VIC 3008, Australia
STOCK EXCHANGE LISTING
Cue Energy Resources Limited securities are listed on the Australian
Securities Exchange.
(ASX code: CUE)
WEBSITE
cuenrg.com.au
4
HI GHL I GH TS
»
»
»
»
»
$44.4 million revenue,
up 98% on FY2021
$16.1 million profit
after tax
$29.0 million
EBITDAX1
Mahato production
and revenue growth
continued
Entry into Australian
gas markets with
the acquisition of
Amadeus Basin
assets
OPERATIONS AND FINANCIAL REVIEW
30 JUNE 2022
A YEAR OF SUSTAINA BLE CH A N GE ,
GROWTH AND IMPROVED P ERFOR M A N C E
Cue experienced substantial growth during FY2022, achieving revenue of $44.4 million,
98% higher than the previous year and Cue’s highest revenue since 2016. This result
was driven by organic and inorganic growth and high prices in the markets in which the
company participates.
Cue’s projects are regionally diversified and by product, with 58% of revenue from oil
with a Brent benchmark basis and 42% from gas on primarily fixed price contracts.
Indonesian operations contributed $27.0 million revenue, New Zealand $9.2 million and
Australia $8.2 million.
$16.1 million profit after tax was reported, up 226% on FY2021, with $29.0 million
EBITDAX recorded.
Cue net sales volume for the year was 583,000 barrels of oil equivalent (boe) at an
average cash cost of $23/boe, achieving a gross profit margin of $102/boe for oil and
$31/boe for gas.
During the year, Cue increased its revenue producing assets to four with the acquisition
of Amadeus Basin fields, Mereenie, Palm Valley and Dingo in central Australia.
This acquisition was completed in October 2021 with these fields contributing $8.2
million in revenue for the year. Gas from these fields is sold into the Australian east
coast market and the local Northern Territory market. The acquisition was well timed,
with contract and spot gas prices on the East Coast of Australia experiencing increases
in the second half of the year.
Drilling of the PV-12 well commenced in April 2022. A change in the drilling program
was announced in early July 2022 and Cue has expensed $0.8 million of exploration
costs associated with the decision to cease drilling to the Arumbera target. On 22
August 2022, Cue announced that the side track targeting the lower P2 and P3
reservoirs had encountered water and drilling ceased. The costs associated with this
side track in total are $2.2 million, of which $1.0 million are expensed in FY2022 and
the balance of $1.2 million will be expensed in FY2023. A new sidetrack is currently
being drilled into the P1 formation.
The PB oilfield in Indonesia’s Mahato PSC experienced significant growth, contributing
$14.9 million revenue during the year, and $7.8 million profit after tax. Production from
PB field is expected to continue growing as 10 production wells are planned to be
drilled during the remainder of FY2023.
The Sampang PSC in Indonesia continued to provide a strong and stable revenue
stream from contracted gas sales contributing $12.1 million in revenue from the Oyong
and Wortel fields. New Zealand’s Maari field, where oil is sold on a Brent benchmark
basis plus a premium, lifted three cargos during the year and benefited from high global
oil prices, with $9.2 million revenue, an increase of 32% over the previous year.
Administration expenses of $2.2 million, excluding business development costs,
remained low as Cue managed non-operated projects efficiently from offices in
Melbourne and Jakarta.
On 24 June 2022, Cue executed an agreement with New Zealand Oil & Gas for a
$7.0 million loan to support Cue’s existing exploration and development activities and
ensure sufficient working capital remains available during expected periods of high
expenditure during FY2023. The loan was fully drawn by the end of FY2022.
1EBITDA is a financial measure which is not prescribed by Australian Accounting Standard (‘AAS’) and represents the profit under AAS adjusted for depreciation, amortisation,
interest and tax. EBITDAX is EBITDA adjusted to exclude business development costs, exploration and evaluation expenses, share based payments and one-off legal expenses.
5
SECTION HEADING
JOINT OPERATIONS
INDONESIA
Mahato PSC
INDONESIA
Texcal (Operator)
Mahato PSC
Central Sumatra Energy
ygrenE tikuB
Texcal (Operator)
Cue
Central Sumatra Energy11.5%
ygrenEtikuB
Cue
Sampang PSC
Medco Energi (Operator)
Sampang PSC
Singapore Petroleum Company
Cue
Medco Energi (Operator)
Singapore Petroleum Company
Cue
51%
11.5%
25%
51%
12.5%
25%
12.5%
45%
40%
15%
45%
40%
15%
Amadeus Basin
Mereenie (OL 4/5)
Amadeus Basin
Central Petroleum (Operator)
Macquarie Mereenie
Mereenie (OL 4/5)
New Zealand Oil & Gas
Central Petroleum (Operator)
Cue
Macquarie Mereenie
Palm Valley (OL 3)
New Zealand Oil & Gas
Central Petroleum (Operator)
Cue
New Zealand Oil & Gas
Palm Valley (OL 3)
Cue
Central Petroleum (Operator)
Dingo (L7)
New Zealand Oil & Gas
Central Petroleum (Operator)
Cue
New Zealand Oil & Gas
Dingo (L7)
Cue
Central Petroleum (Operator)
New Zealand Oil & Gas
Cue
25%
50%
17.5%
25%
7.5%
50%
17.5%
50%
7.5%
35%
15%
50%
35%
50%
15%
35%
15%
50%
35%
15%
NEW ZEALAND
Maari and Manaia Oil Fields
NEW ZEALAND
PMP 38160
Maari and Manaia Oil Fields
OMV (Operator)
Horizon Oil
PMP 38160
Cue
OMV (Operator)
Horizon Oil
Cue
69%
26%
5%
69%
26%
5%
66
NEW ZEALANDINDONESIAAUSTRALIAHead OfficeMelbourneCue JakartaOfficeNEW ZEALANDINDONESIAAUSTRALIAHead OfficeMelbourneCue JakartaOffice
AUSTRALIA
ON SH ORE
NO R TH ERN
T ERRIT ORY
LEGEND
Cue Permit
Oil Field
G
as Field
Oil Pipeline
Gas Pipeline
OL4
Mereenie
OL5
Palm Valley
OL3
N
100km
Alice Springs
Dingo
L7
OPERATIONS AND FINANCIAL REVIEW
30 JUNE 2022
CUE INTERESTS
Mereenie [OL4 & OL5]
7.5%
Palm Valley [OL3]
Dingo [L7]
Operator
15%
15%
Central Petroleum Limited
Cue completed the acquisition of interests in the Mereenie, Palm Valley
and Dingo fields, in the Amadeus Basin, onshore Northern Territory, on
1 October 2021. These fields produce gas which is sold into the high
demand Eastern Australia gas markets and locally in the Northern Territory.
A planned development program of four recompletions and two new
development wells, WM27 and WM28, was successfully undertaken in the
first half of the year in the Mereenie field.
The Palm Valley 12 (PV-12) exploration well spudded 17 April 2022 to
evaluate the gas potential of the Arumbera Sandstone formation at 3,560m.
Drilling experienced very challenging conditions due to fractures at this
crestal location, and extremely hard rock formations. On 12 July, the Joint
Venture (JV) made the decision to stop drilling, having reached a depth
of 2,335m. Flow tests through the lower P2 to P4 interval of the Pacoota
Sandstone demonstrated minor gas flows to surface, and based on these
results, the JV decided to replace the deeper Arumbera exploration target
with an evaluation of the interval via a side track at this level.
The side track was planned to extend for approximately 1,000m, targeting
the lower P2 and P3 formations (P2/P3). On 22 August 2022, Cue announced
that the side track had reached a measured depth of 2431m in the lower
P2/P3. Water was recovered from the wellbore which was determined to
be formation water. This water presence and the absence of significant gas
shows during the drilling led to a decision by the JV to curtail further drilling in
the P2/P3 side track.
Cue has expensed $0.8 million of exploration costs in FY22 associated
with the decision to cease drilling to the Arumbera target. Furthermore,
exploration costs associated with the side track targeting the lower P2 and
P3 reservoirs of $1.0 million were expensed in FY22 and a further $1.2 million
will be expensed in FY23.
Sidetrack operations into the P1 Reservoir of the Pacoota formation, which is
the producing formation at Palm Valley, have commenced.
The Dingo Deep exploration well, scheduled to follow the PV-12 well,
will be deferred so capital can be redeployed to invest in new near-term
development to increase production capacity at Mereenie or Palm Valley.
The Dingo Joint Venture will reassess the priority of the Dingo Deep prospect
at a future date.
The Mereenie JV is finalising plans for up to six well recompletions and two
development wells to increase gas production in the Mereenie field. Subject
to JV and regulatory approvals, this development work is expected to be
undertaken during FY2023.
Exploration permits WA-409-P and WA-389-P were surrendered during
the year. Cue no longer holds permits offshore Australia.
OF F SH ORE
7
OPERATIONS AND FINANCIAL REVIEW
30 JUNE 2022
INDONESIA
MAHATO PSC
8
CUE INTEREST
12.5%
Operator
Texcal Mahato EP Ltd
Production and development continued at the PB Field, with oil
production increasing from 3400 barrels of oil per day (bopd) to
5500 bopd by the start of August 2022 as new production wells were
drilled and brought online. A total of 10 production wells are currently
producing, including PB-17 and PB-18 which were announced in July
and August 2022.
Cue’s revenue for the year was $14.9 million from oil sales, an increase of
more than five times the previous year’s result, which included start-up of the
field in January 2021. Oil sales are based on Brent benchmark price with a
$1-$2/bbl discount and denominated in US Dollars. During the year, Mahato
PSC entered a profit-sharing phase with the Indonesian government under
the Production Sharing Contract (PSC), which results in lower net production
and revenue to Cue than the initial months of production
Production wells PB-06, PB-07, PB-08, PB-09 and PB-18 were drilled during
the year, with production mainly from the Bekasap B and C reservoirs. The
PB-08 well started production from the Bekasap A sand in February 2022 and
was taken offline by April for conversion to a water injection well due to poor
production performance.
In June 2022, Cue announced the approval of a Field Development
Optimisation (FDO) plan for the PB Field by SKKMigas, the Indonesian
regulator. The FDO provides approval for a total of 20 production wells in the
field and three water injection wells. At the end of the year, there were nine
production wells and one injection well in the field, with 11 production wells
to be drilled in FY2023. The first well for the year, PB-17 commenced in early
July 2022 and started production in August at a rate of 800 bopd.
Well depths in the PB field range from 5500-7200ftMD with one month drilling
and completion time expected for each production well. Over the first half of
FY2023, wells are expected to be drilled from the existing well pad in the PB
field. A new well pad and production facilities will be built in the northern area
of the field to produce reserves not accessible from the existing well pad.
Wells are expected to be drilled from this location from H2 FY2023.
Exploration well PBE-1 in the PB field targeting a structure away from the
main PB field, was drilled in July 2021, did not encounter any hydrocarbons
and was plugged and abandoned in early September 2021.
Bangko
Balam South
Sumatra
Mahato
PSC
Duri
Libo SE
LEGEND
Cue Permit
PB Oil Field
Major Oil Fields
PB
Minas
Kotabatak
Petapahan
40km
INDONESIA
SA M PA NG PSC
OPERATIONS AND FINANCIAL REVIEW
30 JUNE 2022
CUE INTEREST
15%
Operator
Medco Energi Sampang Pty Ltd
Sampang PSC fields Oyong and Wortel continued to provide strong
cashflow for Cue, with $12.1 million revenue contribution and
$3.3 million profit after tax.
Development planning continued on the Paus Biru gas field during the year.
The field was discovered by the Paus Biru-1 exploration well and announced
as a gas discovery in December 2018. The approved Plan of Development
(POD) consists of a single horizontal development well with an unmanned
wellhead platform (WHP), connected by a subsea pipeline to the existing
WHP at the Oyong field, approximately 27km away. From the Oyong WHP,
gas from Paus Biru will be transported using the existing pipeline to the Grati
Onshore Production Facility, which is operated by the Sampang PSC joint
venture, for processing and sale.
Front End Engineering and Development (FEED) studies were completed
during the year and the Joint Venture is reviewing these.
Commercial discussions progressed with a gas buyer and the Indonesian
government to define the gas price and production allocation to the buyer.
These issues are substantially complete. Due to the delays in the buyer and
government processes, which delayed the Final Investment Decision (FID)
on the Paus Biru Development, the joint venture has requested incentives
from the government make up for the economic loss caused by the delays.
These incentives include a field extension proposal to allow production for a
further five years after the current permit expiry in 2027. Discussions with the
government are proceeding well.
The JV expects to take a final investment decision (FID) is in Q2 FY2023, with
first gas production forecast for the start of 2025 at an estimated rate of 20 to
25 million cubic feet per day (mmcfd).
Java
Madura Island
East Java
Wortel
Maleo
Jeruk
Oyong
Paus Biru
Grati Onshore
Gas Facilities
30km
Peluang
LEGEND
Cue Permit
Oil Field
Gas Field
9
OPERATIONS AND FINANCIAL REVIEW
30 JUNE 2022
NEW ZEALAND
PMP 38160
(MAARI)
CUE INTEREST
5%
Operator
OMV New Zealand Limited
Maari continued to generate strong revenue of $9.2 million though the
year, an increase of $2.2 million over the previous year.
The MR6a production well, which was shut-in during May 2021 due to sand
production, was offline during the period, with an estimated loss of 1000bopd
production. Temporary de-sanding equipment was installed and tested on
the Well Head Platform during Q4 FY2022. Although the equipment
performed well, the process was not successful in producing hydrocarbons
from the well and the equipment has been removed. The operator is
preparing plans to enter the well and plug off the damaged section to enable
oil production from part of the existing wellbore, which is expected to be
completed in H1 FY2023.
Workovers to replace Electric Submersible Pumps (ESP) on MR8 and MN1
production wells were undertaken during the year and subsequent to the year
end. Finalisation of the MN1 repairs are ongoing.
During the year, the New Zealand Government passed the Crown Minerals
(Decommissioning and Other Matters) Amendment Bill which, amongst other
things, changes the decommissioning obligations of Permit holders. Cue is
reviewing the new requirements and the associated regulations, which are yet
to be finalised, and has provided feedback to the government.
Regulatory approval processes for Jadestone Energy to acquire 69%
operated working interest in Maari from OMV, which was announced in 2019
are continuing.
New Zealand
LEGEND
Cue Permit
Oil Field
Gas Field
Taranaki
Peninsula
Tui
Maui
Maari
Manaia
PMP 38160
10km
10
OPERATIONS AND FINANCIAL REVIEW
30 JUNE 2022
RISKS
Cue’s business, operating and financial results and performance are subject to various risks and uncertainties, some of
which are beyond Cue’s reasonable control. Set out below are matters which Cue has assessed as having the potential
to have a material impact on the business, operating and/or financial results and performance. These matters may
arise individually, simultaneously or in combination. The matters identified below are not necessarily listed in order of
importance and are not intended as an exhaustive list of all the risks and uncertainties associated with Cue’s business.
External economic drivers (including macroeconomic, oil prices, exchange rates and costs)
The consolidated entity’s primary focus is oil and gas exploration, development and production. Fluctuations in the
oil price can result from various aspects beyond Cue’s control, including macroeconomic and geopolitical. Sustained
lower oil prices would adversely affect Cue’s financial performance.
Failure to discover new, or extend existing exploration and production wells and production from existing wells
Cue’s current and future business, operating and financial performance and results are impacted by the discovery
of new exploration wells and the performance of new and existing production wells in order to produce oil and
gas. Results may differ significantly from estimates determined at the time the relevant project was approved for
development. Cue’s current or future development activities may not result in expansion or replacement of current
production wells, or one or more new production wells or facilities may be less profitable than anticipated or may not be
profitable at all.
Joint venture arrangements
Cue has joint venture interests in all its Projects. These operations are subject to the risks normally associated with
the conduct of joint ventures which include (but are not limited to) disagreement with joint venture partners on how
to develop and operate the projects efficiently, inability of joint venture partners to meet their financial and other joint
venture commitments and particular risks associated with entities where a sovereign state holds an interest, including
the extent to which the state intends to engage in project decision making and the ability of the state to fund its share
of project costs. The existence or occurrence of one or more of these circumstances or events may have a negative
impact on Cue’s future business, operating and financial performance and results, and/or value of the underlying asset.
11
RESERVES AND RESOURCES
30 JUNE 2022
Cue has increased its 2P Reserves during the financial year to 6.6 million barrels of oil equivalent with a
reserves replacement ratio of 122%.
As at June 30, 2022 Cue has reported 4.6 mmboe of proven (1P) reserves and 6.6 mmboe of Proven and Probable
(2P) reserves. 67% of reported 2P reserves are gas and 33% are oil.
The largest increase in reserves is due to increases at the PB field in the Mahato PSC, where analysis was conducted
based on improved field information from production wells. Cue has reported 0.5mmstb of developed 2P reserves
which are expected to be produced from wells existing at June 30 2022 and 0.5mmstb of undeveloped 2P reserves,
which are expected to be accessible from the current phase of production drilling, where 11 production wells are
expected to be drilled during FY2023.
Reserves in the Mereenie field have been reviewed and reduced during the year based on internal assessment of an
independent reserves report undertaken by the Operator of the field, Central Petroleum. This same report was used as
a basis for review of the Palm Valley and Dingo fields and resulted in minor variations to previously published reserves.
Maari, and Oyong and Wortel fields in the Sampang PSC, have performed as expected during the year, with reserves
adjusted for production during FY2022.
Cue’s 2P reserve replacement ratio for FY2022 is 122%, taking into account reserves additions and production during
the year.
6.6
mmboe
6.6
mmboe
12
Mereenie2.1Palm Valley0.6Dingo1.0Maari0.6Sampang PSC0.8Mahato PSC1.42P reserves by Asset (mmboe)oil2.2gas4.4Gas/Oil 2P reserves (mmboe) RESERVES AND RESOURCES
30 JUNE 2022
RESERVES AND RESOURCES NET TO CUE AS AT 30 JUNE 2022
1P
1P
DEVELOPED
UNDEVELOPED
1P
TOTAL
1P RESERVES (PROVEN)
GAS
OIL
EQUIVALENT
GAS
OIL
EQUIVALENT
GAS
OIL
EQUIVALENT
COUNTRY
FIELD/PERMIT
PJ MMSTB MMBOE
PJ
MMSTB
MMBOE
PJ
MMSTB
MMBOE
AUSTRALIA
Mereenie
Palm Valley
Dingo
NEW ZEALAND Maari
INDONESIA1
Sampang PSC
Mahato PSC
TOTAL
7.5
2.7
2.0
0.0
3.1
0.0
15.3
0.1
0.0
0.0
0.3
0.0
0.8
1.2
1.3
0.4
0.3
0.3
0.5
0.8
3.6
1.3
0.0
3.1
0.0
0.0
0.0
4.4
0.0
0.0
0.0
0.0
0.0
0.3
0.3
0.2
0.0
0.5
0.0
0.0
0.3
1.0
8.8
2.7
5.1
0.0
3.1
0.0
19.7
0.1
0.0
0.0
0.3
0.0
1.1
1.5
1.5
0.4
0.8
0.3
0.5
1.1
4.6
2P RESERVES
(PROVEN & PROBABLE)
2P
2P
DEVELOPED
UNDEVELOPED
2P
TOTAL
GAS
OIL
EQUIVALENT
GAS
OIL
EQUIVALENT
GAS
OIL
EQUIVALENT
COUNTRY
FIELD/PERMIT
PJ MMSTB MMBOE
PJ
MMSTB
MMBOE
PJ
MMSTB
MMBOE
AUSTRALIA
Mereenie
10.5
Palm Valley
Dingo
NEW ZEALAND Maari
INDONESIA1
Sampang PSC
Mahato PSC
TOTAL
3.9
2.3
0.0
5.0
0.0
21.7
0.1
0.0
0.0
0.4
0.0
1.0
1.5
2C CONTINGENT RESOURCES3
COUNTRY
FIELD/PERMIT
AUSTRALIA Mereenie
Palm Valley
INDONESIA
Paus Biru (Sampang PSC)
Jeruk (Sampang PSC)2
TOTAL
1.8
0.6
0.4
0.4
0.8
1.0
5.1
GAS
PJ
13.7
2.1
0.0
7.0
22.8
1.8
0.0
3.6
0.0
0.0
0.0
5.4
0.0
0.0
0.0
0.2
0.0
0.5
0.7
0.3
0.0
0.6
0.2
0.0
0.5
1.5
12.4
3.9
5.8
0.0
5.0
0.0
27.1
0.1
0.0
0.0
0.6
0.0
1.4
2.2
2.1
0.6
1.0
0.6
0.8
1.4
6.6
OIL
TOTAL
MMSTB
MMBOE
0.0
0.0
1.2
0.0
1.2
2.3
0.3
1.2
1.1
5.0
PJ Petajoules
MMSTB Million Stock Tank Barrels
MMBOE Million Barrels of Oil Equivalent
(1) Indonesian Reserves are net of Indonesian Government share of Production. Production Sharing Contract (PSC) adjustments affect the net
equity across the various reserve categories
(2) Cue interest in Jeruk is 8.18%
(3) Paus Biru Contingent Resources have been sub-classified under the PRMS as “Development Pending” which represents A discovered
accumulation where project activities are ongoing to justify commercial development in the foreseeable future. Other Contingent Resource
have been sub-classified as “Development Unclarified” which represents a discovered accumulation where justification of a commercial project
is unknown based on available information and plans to develop are not yet considered near-term.
13
RESERVES AND RESOURCES
30 JUNE 2022
GOVERNANCE ARRANGEMENTS AND INTERNAL CONTROLS
Cue estimates and reports its petroleum reserves and resources in accordance with the definitions and guidelines of
the Petroleum Resources Management System 2018 (SPE-PRMS), published by the Society of Petroleum Engineers
(SPE). All estimates of petroleum reserves reported by Cue are prepared by, or under the supervision of, a qualified
petroleum reserves and resources evaluator. Cue has engaged the services of New Zealand Oil & Gas Limited (NZOG)
to independently assess the all reserves. Cue reviews and updates its oil and reserves position on an annual basis, or
as frequently as required by the magnitude of the petroleum reserves and changes indicated by new data and reports
the updated estimates as of 30 June each year as a minimum.
RESERVES COMPLIANCE STATEMENT
Oil and gas reserves, are reported as at 1 July 2022 and follow the SPE PRMS Guidelines (2018).
This resources statement is approved by, based on, and fairly represents information and supporting documentation
prepared by New Zealand Oil & Gas Assets & Engineering Manager Daniel Leeman. Daniel is a Chartered Engineer
with Engineering New Zealand and holds Masters’ degrees in Petroleum and Mechanical Engineering as well as a
Diploma in Business Management and has over 14 years of experience. Daniel is also an active professional member
of the Society of Petroleum Engineers and the Royal Society of New Zealand. New Zealand Oil & Gas reviews reserves
holdings twice a year by reviewing data supplied from the field operator and comparing assessments with this and
other information supplied at scheduled Operating and Technical Committee Meetings.
Daniel is currently an employee of New Zealand Oil & Gas Limited whom, at the time of this report, are a related party
to Cue Energy. Daniel has been retained under a services contract by Cue Energy Resources Ltd (Cue) to prepare an
independent report on the current status of the entity’s reserves. As of the 17th of January 2017, NZOG held an equity
of 50.04% of Cue.
Cue currently holds an equity position of 5%, 12.5% and 15% in the Maari, Mahato and Sampang assets respectively,
though Production Sharing Contract adjustments at the Mahato and Sampang fields affect the net equity differently
across the various reserve categories.
In the Amadeus basin, Cue currently holds 7.5% equity in the Mereenie field and 15% equity in each of the Dingo
and Palm Valley fields. For Sampang PSC Contingent Resources, as the developments are not yet sanctioned, the
economics and royalties are not yet known, therefore an assumed net effective equity is used of 15% for Paus Biru
and 8.18% for Jeruk.
Estimates are based on all available production data, the results of well intervention campaigns, seismic data,
analytical and numerical analysis methods, sets of deterministic reservoir simulation models provided by the field
operators (OMV, Texcal, Medco and Central Petroleum), and analytical and numerical analyses. Forecasts are based
on deterministic methods.
For the conversion to equivalent units, standard industry factors have been used of 6Bcf to 1mmboe, 1Bcf to 1.05PJ
and 1TJ of gas to 163.4 boe.
Proven (1P) reserves are estimated quantities of oil and gas which geological and engineering data demonstrate
with reasonable certainty (90% chance) to be recoverable in future years from known reservoirs, under existing
economic and operating conditions. Probable (2P) reserves have a 50% chance or better of being technically
and economically producible.
Known accumulations are reserves or contingent resources that have been discovered by drilling a well and testing,
sampling, or logging a significant quantity of recoverable hydrocarbons.
Net reserves are net of equity portion, royalties, taxes and fuel and flare (as applicable).
Developed reserves are expected to be recoverable from existing wells and facilities. Undeveloped reserves will be
recovered through future investments (e.g. through installation of compression, new wells into different but known
reservoirs, or infill wells that will increase recovery). Total reserves are the sum of developed and undeveloped reserves
at a given level of certainty.
All reserves and resources reported refer to hydrocarbon volumes post-processing and immediately prior to point of
sale. The volumes refer to standard conditions, defined as 14.7psia and 60°F.
14
The extraction methods are as follows; for Maari oil is produced to the FPSO Raroa and directly exported to
international oil markets, at Mahato, it is via EPF facilities which includes an oil and water separation system, with the
RESERVES AND RESOURCES
30 JUNE 2022
oil then piped 6km to the CPI operated Petapahan Gathering Station, at Sampang, gas is gathering from the Wortel
and Oyong fields and piped to shore where it is sold into the Grati power station, at the Mereenie and Palm Valley
gas fields gas is gathered from the wells and ultimately collated into the Amadeus Gas Pipeline where sales vary to
different customers within the region and further afield and at Dingo, gas is sold into Alice Springs and the Owen
Springs power plant.
Tables combining reserves have been done arithmetically and some differences may be present due to rounding.
There have been no material changes in Contingent Resource booking since the last reporting period.
For the 2P change of reserves year-on-year, quoted as the reserves replacement ratio herein, the calculation is
performed via; stated 2P total reserves as at 1 July 2022, divided by the sum of stated 2P total reserves as at 1 July
2021, less production during FY22, all in millions of barrels of oil equivalent. In this case RRR = 6.6 / (6.0-0.6) = 122%.
RESERVES AND RESOURCES RECONCILIATION WITH 30 JUNE 2021
1P RESERVES (MMBOE)
COUNTRY
FIELD/PERMIT
30 JUNE 2021
DISCOVERIES/
EXTENSIONS/
REVISIONS
PRODUCTION
30 JUNE 2022
AUSTRALIA
Mereenie
Palm Valley
Dingo
NEW ZEALAND Maari
INDONESIA
Sampang PSC
Mahato PSC
TOTAL
2P RESERVES (MMBOE)
2.2
0.6
0.7
0.3
0.4
0.3
4.4
-0.5
-0.1
0.2
0.1
0.4
0.8
0.9
0.2
0.1
0.0
0.1
0.3
0.0
0.6
1.5
0.4
0.8
0.3
0.5
1.1
4.6
COUNTRY
FIELD/PERMIT
30 JUNE 2021
DISCOVERIES/
EXTENSIONS/
REVISIONS
PRODUCTION
30 JUNE 2022
AUSTRALIA
Mereenie
Palm Valley
Dingo
NEW ZEALAND Maari
INDONESIA
Sampang PSC
Mahato PSC
TOTAL
2.6
0.6
0.9
0.7
0.8
0.4
6.0
-0.3
0.1
0.1
0.0
0.3
1.0
1.2
0.2
0.1
0.0
0.1
0.3
0.0
0.6
2.1
0.6
1.0
0.6
0.8
1.4
6.6
2C CONTINGENT RESOURCES (MMBOE)
COUNTRY
FIELD/PERMIT
30 JUNE 2021
DISCOVERIES/
EXTENSIONS/
REVISIONS
PRODUCTION
30 JUNE 2022
AUSTRALIA Mereenie
Palm Valley
Dingo
INDONESIA
Jeruk (Sampang PSC)
Paus Biru (Sampang PSC)
TOTAL
2.3
0.3
0.0
1.2
1.1
4.9
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2.3
0.3
0.0
1.2
1.1
5.0
15
SUSTAINABILITY
30 JUNE 2022
HEALTH SAFETY AND ENVIRONMENT
Cue is committed to achieving and maintaining good health, safety, and environmental performance, which we
consider critical to the success of our business. We operate under a Health Safety and Environment HSE Policy
approved by our Board of Directors and a HSE Management system.
We have an Operational Risk and Sustainability (ORS) committee of the Board of Directors. This committee meets
regularly to review the company’s HSE activities and operational risks.
Cue recorded zero incidents, zero lost time injuries and zero significant spills within Cue Energy Resources Limited’s
operations over the past year. However, there were two Lost Time Injuries (LTI) at sites not operated by Cue, one at the
Maari Joint Venture and one at the Palm Valley Joint Venture. Cue regularly reviews all incidents and Health and Safety
reporting at our projects and provides input and feedback to assist with the safe running of all operations.
Cue has continued to operate with extra measures in place due to COVID-19 to protect Cue and partners. Our joint
venture projects have implemented COVID plans to reduce the risk to staff and minimise the impact to operations.
Cue staff in our Melbourne and Jakarta offices have worked remotely where advised, in line with local government
regulations and company assessed risks.
Our employee assistance program continues to be available for employees to provide support where requested.
16
16
SUSTAINABILITY
30 JUNE 2022
SUPPORTING COMMUNITIES
To keep our social licence to operate in good standing, Cue continues to support the communities in which we
operate, and we are proud to assist our partners in their community activities. Cue aims to actively promote
opportunities for economic benefits to be realised locally and regionally through our Capturing Local Economic
Benefits Policy, and we encourage our partners to do this also.
OMV NZ, the Maari field’s operator, continues to actively support a number of community initiatives in Taranaki.
Sponsorship renewals were signed with WISE Charitable Trust, Roderique Hope Trust, where $30,000 from the
sale of surplus office equipment was donated to help secure a permanent building for the Trust to work out of, and
Paper4Trees, demonstrating commitment to these worthy causes.
OMV has also long supported the Rotokare Scenic Reserve Trust and will continue to do so.
Central Petroleum, the operator of Cue’s Amadeus Basin assets, works closely with the communities in which it
operates, relies on the on the support of local communities, landowners, and other stakeholders and aims to provide
employment and business opportunities to local communities. Over $4 million was spent with Northern Territory local
contractors and businesses in FY2022.
In the Northern Territory, over half or Central’s staff live locally and a quarter are indigenous.
Cue supports Central’s commitment to engaging openly with the Traditional Owners of our NT joint operations that
are located on or near Indigenous lands and providing employment and training opportunities. As our joint venture
operator, Central works closely with the Central Land Council and Aboriginal Areas Protection Authority to ensure our
operations do not disturb areas of cultural heritage significance.
During calendar year 2021, Sampang PSC Joint Venture Operator Medco Energi invested more than US$200,000 in
the local community. In 2022, this support will focus on fishing programs, as this is a major industry in the Sampang
area, as well as public facility upgrades and continued support of socioeconomic programs for micro and small
business enterprises, including participation in Medco Energi Community Program of Small Home Industry at the
UMKM Mini Fair.
A total of 2,500 acacia trees were planted in Taddan Village, Sampang Regency, as part of a joint venture project with
SKK Migas and the Sampang Government.
Greening Program in Sampang Regency, Indonesia
UMKM Mini Fair at Sumenep Regency, Indonesia
17
TASKFORCE ON CLIMATE–RELATED FINANCIAL
DISCLOSURES (TCFD) STATEMENT
30 JUNE 2022
This section outlines the Cue Energy Resources approach to climate change.
It is structured to provide an overview the core elements of the Task Force on Climate - related Financial Disclosures
(TCFD):
» Governance
» Strategy
» Risk management, and
» Metrics and Targets
1. STATEMENT ON CLIMATE CHANGE FROM THE CHIEF EXECUTIVE
Cue recognises the scientific consensus of climate change and the need to reduce global emissions.
These issues are significant for us, our stakeholders and the communities in which we work.
Our community expects that we will use our endeavours to help to provide reliable supply of energy at efficient prices
and at the same time transition to a lower carbon world.
In 2022, the world has experienced a shortage of reliable energy. Recent energy constraints at home in Australia has led
to increased expectations that gas producers will maximise production. In Indonesia, our gas production played a small
part in helping to meet the urgent demands of a developing economy.
At Cue, we are proud to have helped meet these human needs, but we also recognise that emissions from fossil fuels
need to reduce in order to reduce the risks posed by climate change .
We keep an active watch on our own operations and, where it’s practical, reduce our carbon impact. We support our
joint venture partners to reduce the carbon footprint of Projects that we are involved in.
In this report, we outline our own emissions impact and we endeavour to help investors and other stakeholders
to understand the risks linked to climate change by reporting our emissions, material climate change risks to the
business, our governance, strategy and risk response to managing climate risks.
The gas we produce is an ideal partner to renewable energy, and with decades of transition to renewable fuels ahead,
gas will remain part of our energy system. Our strategy is to manage our own emissions responsibly, and to provide
energy options that support the transition.
Cue’s New Zealand hydrocarbon production is subject to emissions pricing in New Zealand. Under the New Zealand
Emissions Trading Scheme, Cue purchases credits that offset emissions from our share of the Maari Production
facilities. The emissions trading scheme has the economic effect of disincentivising wasteful emissions and rewarding
renewable or low carbon initiatives.
Indonesia is a developing economy that faces profound challenges to decarbonise with a rapidly growing population.
The energy market is dominated by coal fired electricity generation and Cue is helping reduce emissions by supplying
gas to Indonesia Power’s Grati power plant. Gas-fired electricity, that the Grati plant supplies to East Java, produces
half the emissions of coal-fired alternatives. Indonesia is in the process of establishing a carbon market and Cue is
following the progress of these regulations.
Cue offices in Melbourne and Jakarta have introduced initiatives to reduce our own carbon footprint. We upgraded
IT and lighting equipment with lower power replacements and we continue to focus on initiatives to keep our own
emissions low. We offset office emissions by planting trees.
We have expanded our TCFD reporting, and now we are able to report on emissions from our Sampang and Mahato
assets in Indonesia and Maari in New Zealand.
Our Board Operational Risks and Sustainability Committee reviews and manages climate risks within our broader risk
management framework, and it has reviewed and approved this statement.
We are pleased to present this report outlining our climate change strategy, governance, risk management and targets.
Matthew Boyall
Chief Executive Officer
18
TASKFORCE ON CLIMATE–RELATED FINANCIAL
DISCLOSURES (TCFD) STATEMENT
30 JUNE 2022
2. GOVERNANCE
TCFD CATEGORY
RECOMMENDATION
SUMMARISED IN
THIS DOCUMENT AT
Governance
Disclose the organisation’s governance
around climate-related risks and opportunities
Describe the board’s oversight of climate
related risks and opportunities
Describe management’s role in assessing and
managing climate-related risks and opportunities
2.2, 2.3
2.2, 2.3
2.2, 2.3
2.1 CLIMATE-RELATED RISK GOVERNANCE PROCESS
BOARD OF DIRECTORS
• Board Charter
• Cue Risk Management System
• ASX Listing Rules and Corporate Governance Code
(E.g. Principal 7, Recognise and Manage Risk)
• Reviews reports from Operational Risk and Sustainability
Committee and manages response
BOARD OPERATIONAL RISK AND SUSTAINABILITY COMMITTEE
• Reviews risks, including changes in risks reported from risk
owners and management.
• Reports risks and opportunities to Board
CUE MANAGEMENT
• Regularly reviews and updates risk register.
• Allocates risk to risk owners.
• Reports risk register to ORSC.
STAFF HEALTH, SAFETY AND
ENVIRONMENT PROCESS
•
Identifies and reviewed site HSE incidents
and incorporates these into the risk
register
19
TASKFORCE ON CLIMATE–RELATED FINANCIAL
DISCLOSURES (TCFD) STATEMENT
30 JUNE 2022
2.2 BOARD OVERSIGHT
The Board has responsibility for reviewing all risks, including climate-related risk and opportunities,
and ensuring these are appropriately managed to support delivery of our business strategy.
Recognising and managing risks is an overarching Board accountability under its charter ((2.2 (h))
A copy of the Charter is here:
http://www.cuenrg.com.au/site/PDF/3b70602c-3455-4908-8608-fac20445ca6a/BoardCharter?IncludeUnapprov
ed=44923881
The Board reserves to itself specific responsibility to:
“Understand the material risks faced by the Company and ensure the Company has appropriate risk management
strategies and control measures in place and is actively managing these.”
—Board Charter, 3.3 (h).
The process for considering risks is set out in the company’s risk management system framework.
The framework meets the requirements of the ASX Corporate Governance Principles and Recommendations,
Principle 7: Recognise and Manage Risk.
The Board Operational Risk and Sustainability Committee (ORSC) sets, reviews and agrees relevant risk policies,
practices, frameworks, targets and performance. Its Charter includes climate change responses.
See ORSC Charter, Schedule 1, #2: The ORSC Charter is here:
http://www.cuenrg.com.au/site/PDF/b8ca96e1-411c-4004-a637-7e6d4fc6fe1c/OperationalRiskandSustainabilityCom
mitteeCharter?IncludeUnapproved=91154364
Cue’s risk register assesses risks related to climate policy, climate-related events, and public perception.
Examples of risks are disclosed below in the section titled Climate-Related Risks.
Management is responsible for identifying, assessing and managing risk and reporting this to the Board through
the ORSC. Management risk owners identify and manage risks. Management regularly reviews the corporate risk
framework, including the risk register. The ORSC receives a report on updates to the register.
Management retains specialist expertise to review risk management
At an operational level, responsibility for day-to-day oversight of climate risk and opportunity (including managing
climate objectives and targets) rests with the Chief Executive.
3. STRATEGY
TCFD CATEGORY
RECOMMENDATION
SUMMARISED IN
THIS DOCUMENT AT
Disclose the actual and potential impacts of climate-
related risks and opportunities on the organisation’s
businesses, strategy and financial planning where such
information is material.
Describe the climate related risks and opportunities
the organisation has identified over the short, medium
and long term.
Describe the impact of these risks on businesses,
strategy and financial planning.
Describe the resilience of the organisation’s strategy,
taking into consideration different climate related
scenarios including a 2 degree celsius or lower scenario.
3.1
3.2, 4.3
3.3
3.4
Strategy
20
TASKFORCE ON CLIMATE–RELATED FINANCIAL
DISCLOSURES (TCFD) STATEMENT
30 JUNE 2022
3.1
ACTUAL AND POTENTIAL IMPACTS OF CLIMATE-RELATED RISKS AND OPPORTUNITIES
ON THE ORGANISATION’S BUSINESSES, STRATEGY AND FINANCIAL PLANNING
Climate change and climate-related financial and regulatory behaviour require production of natural gas to support
renewable fuels through the transition to a low emissions future.
The Company’s asset base includes natural gas production for Indonesian and East Coast Australian markets that are
energy constrained and hungry for gas to generate electricity that would otherwise likely come from coal generation.
The Company’s forecasts indicate constrained markets will be sustained for several years, with continued economic
value for our production.
3.2. GAS DEMAND WILL BE STRONG FOR SOME TIME
Short Term
Gas demand in the current financial year is high, reflected in high prices, and it is likely to remain significantly elevated,
partly due to geopolitical changes. Regulatory and financing effects make new production less responsive to elevated
prices, meaning production from existing assets is less likely to taper quickly.
Although global demand for oil was reduced significantly during the early stages of the COVID-19 pandemic, the
International Energy Agency (IEA) forecasts demand growth over the next five years. This demand recovery, coupled
with lower recent investment levels in new supply sources is expected to maintain robust commodity prices.
Medium Term / Long Term
The IEA and other forecasters expect global gas demand to begin to plateau in the 2020s, and reduce from the 2030s,
although long-term there will be pressure for gas to replace the higher emissions of coal, especially in developing
economies where demand is expanding faster than renewable energy can supply. Uncertainty over the gas demand
and supply picture is higher as 2050 approaches, due to uncertainty over technology, regulation, the economies of
developing countries, and carbon pricing instruments.
Under the IEA Stated Policies Scenario (STEPS) and Announced Pledges Scenario (APS), oil demand is expected to
remain flat or have a controlled decline between 2030 and 2050. This is expected to be matched by reduced supply
as major international companies diversify spending to alternative fuels. Oil demand is halved between 2030 and 2050
under the IEA Sustainable Development Scenario (SDS).
3.3.
REGULATION IS LIKELY TO INCREASE IN AUSTRALIA AND NEW ZEALAND,
CARBON PRICES ARE LIKELY TO RISE, AND LIMITS ARE LIKELY TO BE IMPOSED
ON EMISSIONS FROM DOMESTIC CONSUMPTION.
In anticipation of higher carbon prices, the Company’s sensitivity testing includes a shadow carbon price when
screening new investments and testing of existing assets.
The Company applies sensitivity testing to its assets and reviews assets for impairment as part of our financial audit
and assurance processes. This testing reviews whether asset valuations have been materially affected by climate-
created conditions, including effects on prices, costs, insurance, financing and abandonment. Sensitivity and
impairment testing manages economic risks to assets. Where those risks change materially, disclosure is made under
the Company’s continuous disclosure obligations.
Resilience to physical risks, such as weather events, is reviewed as a normal part of engineering risk management.
Regulatory risks are mitigated by having revenue producing assets in three diverse jurisdictions.
The Company complies with existing regulations. Its emissions in New Zealand are subject to an emissions trading
scheme, which requires the Company to purchase carbon credits (NZUs) and surrender one for each tonne of carbon
emitted.
Emissions from Scope 3 use (use of oil and gas products by other businesses and consumers) are not able to be
reliably measured, are subject to double counting of total emissions, and are not meaningful in jurisdictions applying
national emissions caps.
All Cue produced gas in Indonesia and most in Australia is used in electricity generation. The balance of electricity
generation in Australia and Indonesia means that gas from Cue substitutes for higher emissions alternative non-
renewable sources.
21
TASKFORCE ON CLIMATE–RELATED FINANCIAL
DISCLOSURES (TCFD) STATEMENT
30 JUNE 2022
3.4. RESILIENCE IN ALTERNATIVE SCENARIOS
The Company monitors the International Energy Agency’s World Energy Outlook, and models produced by industry
leaders such as the BP Energy Outlook, the IPCC and international consultancies.
In all scenarios, we expect to see increased demand for gas in Asian markets. A more rapid decarbonisation outlook
implies a faster switch to gas in Asian markets, and reduced or stable use in Australia and New Zealand. In Indonesia
we see a continuing switch to natural gas from coal, and steady demand for oil as the economy develops.
Gas fields cannot easily or quickly increase supply in response to increased demands, and therefore increased
demand is likely to contribute upward price pressure.
Gas production in Australia is resilient to faster-than expected uptake of renewable generation as coal fired power
generation is likely to be replaced by gas more rapidly than previously predicted.
If oil prices fall significantly, our interests in the Mahato and Maari oil fields may be affected. This risk is reflected in the
forward price curve that forms the basis of impairment analysis and reviews of the expected value of the asset.
Resilience to financial or economic changes is tested as part of financial audit and assurance processes, which
includes impairment testing. Financial planning incorporates expected prices and revenues, including carbon costs,
insurance costs, maintenance costs, and the availability of corporate finance. Specific material risks or changes to
financial outlooks are disclosed in financial reports where these are material.
4. RISK MANAGEMENT
TCFD CATEGORY
RECOMMENDATION
SUMMARISED IN
THIS DOCUMENT AT
Risk management
Disclose how the organisation identifies,
assesses and manages climate-related risks
Describe the process for identifying
and assessing climate risks.
Describe processes for managing climate risks.
Describe how processes for identifying, assessing and
managing are integrated into overall risk management.
4.1
4.1
4.1
4.1
4.1 HOW WE IDENTIFY, ASSESS AND MANAGE CLIMATE-RELATED RISKS
The Company’s Risk Management System Framework applies consistent and comprehensive risk management
practices. Climate risks are recorded in the central risk register, which considers the risks, reviews the controls,
assigns ownership of a risk and tracks treatment plans.
Climate risks are identified on an ongoing basis. Consideration is given to industry and peer information and expertise,
shareholder and community feedback, regulatory changes, and analysis by our own staff and contractors.
Risk assurance and oversight of climate risk management is provided through internal review by the Board ORSC.
The Chief Executive has responsibility for climate risk, including risks to individual assets and financial and investment
risks associated with climate change.
Potential risks to Cue Energy Resources from climate change are assessed under the following headings:
» Policy and Legal,
» Physical (acute and chronic),
»
» Social/Political/Regulatory, and
»
Financial and Market,
Technological.
All these risks have potential financial and operational implications due to lost profitability and increased delays.
Financial and market risks, and social/political risks also present opportunities associated with more rapid uptake of
natural gas as a lower-carbon replacement for coal.
22
TASKFORCE ON CLIMATE–RELATED FINANCIAL
DISCLOSURES (TCFD) STATEMENT
30 JUNE 2022
4.2 CALCULATING CLIMATE RISKS IN ASSET MODELS
Physical risks associated with climate are assessed in engineering planning. For forward price risk associated with
production, the company uses impairment testing based on forward market prices and contracts.
New Zealand
For our New Zealand Maari asset, Cue uses the New Zealand ETS market pricing for carbon emissions. The
Company purchases NZUs annually. (NZUs are New Zealand emissions units, reflecting a tonne of carbon emitted.
One unit must be surrendered to the government each year for each tonne of carbon emitted.) The expected price of
NZUs is modelled in Maari performance forecasts and impairment testing. As NZU prices have been rising quickly,
future prices will be based on expected government policy toward the carbon market.
Australia
There is currently no mandated carbon pricing mechanism in Australia for Cue emissions.
For investment into the Amadeus basin assets, Cue’s advisers used a range of sensitivities to test the economics of
the investment based on market prices in other comparable international regimes.
Expectations of forward prices reflect the market consensus on the likelihood and level of future carbon charges and
market demand. Potential increased carbon pricing or reduced prices are part of the Company’s sensitivity testing and
reflect international comparators as well as assessment of Australian government policy.
Indonesia
Emissions from the company’s interest in the Sampang and Mahato PSCs are considered in performance forecasts
and impairment testing. A carbon cost mechanism is currently being implemented in Indonesia. Under current timing,
a carbon price is expected to be fully implemented by 2025.
The Company monitors the economic effects of climate-related policy and climate conditions on the value and
operation of its assets. Due to uncertainty about future carbon pricing mechanisms and the rapidly changing policy
positions in some countries where the Company operates and investigates new projects, carbon price testing is
undertaken using the most available information and estimates at the time.
For physical risks to all our asset interests, the Company has comprehensive insurance.
4.3 RISK TYPES AND CONTROLS
The table of risks below uses the following time horizon categories:
» Short - 0-5 years,
» Medium - 5-10 years,
»
Long -
10+ years.
RISK TYPE
RECOMMENDATION
DESCRIPTION
TIME
CONTROL
Non
physical
risks
Policy and
legal risks
Litigation against companies and/or
directors on climate grounds (claiming
causation or seeking greater action to
mitigate effects) could have reputational,
development and operating cost
impacts.
Risk of regulatory backlash against ESG
initiatives.
Changing regulations including bans
and restrictive regulations, taxes and
emissions limits across all jurisdictions
risk viability of projects
s, m, l. Board and management understand
their fiduciary duties around climate
change risk.
Internal processes include due diligence
and joint venture processes to identify
and manage climate risk.
Monitoring the jurisdictions where we
undertake activities.
Strategy of diversifying jurisdictions
to mitigate changes on any individual
regulatory environment.
Reporting on climate related
governance, strategy, risks and targets.
Reputational and
social license risks
Stakeholder disengagement and
oppositional activism. Loss of social
license, leading to project delays or
stoppages.
Recruitment and retention risk.
s, m, l. Manage environmental performance.
Due diligence screening of commercial
opportunities and joint ventures.
23
Financial risks
ESG investing affects availability and
s, m, l.
Shadow price on carbon to sensitivity
cost of capital.
testing in investment decisions.
Insurance premiums increase. Potential
for classes of assets and locations to
become uninsurable.
Capital cost increases if new
environmental standards require
more expensive supplies relative to
alternatives.
Carbon pricing adopted across
jurisdictions, or inconsistently between
them.
Changes to price and cost forecasts
result in stranded assets or reserves.
s, m, l.
m, l.
s, m, l.
Due diligence screening of commercial
opportunities and joint venture
processes.
forecasts.
Assurance relating to insurance
Access to a range of funding options.
Reporting on climate related
s, m, l.
governance, strategy, risks and targets.
Jurisdictional diversification to avoid
impact of sudden, unilateral changes,
confiscation or value destruction by
regulation.
Physical
Acute & Chronic
To increased frequency and intensity of
m, l.
Engineering anticipates environmental
risks
extreme weather events such as storms,
conditions.
Oppor-
tunities
Commercial
Global reduction in high carbon sources
s, m, l. Strategic preference for natural gas.
flooding, coastal inundation, lack of
water availability, or slips.
Offshore drilling and production delayed
or shut in by increased weather events.
such as coal is increasing demand for
natural gas as a lower carbon partner to
renewables.
Carbon policy provides for review
of climate issues in strategic and
operational decisions.
Support for our joint venture partners
pursuing low carbon innovations on
sites.
5. MEASUREMENTS AND TARGETS
TACFD CATEGORY
RECOMMENDATION
SUMMARISED IN
THIS DOCUMENT AT
TASKFORCE ON CLIMATE–RELATED FINANCIAL
DISCLOSURES (TCFD) STATEMENT
30 JUNE 2022
RISK TYPE
RECOMMENDATION
DESCRIPTION
TIME
CONTROL
Non
physical
risks
Reputational and
social license risks
Financial risks
Physical
risks
Acute & Chronic
Oppor-
tunities
Commercial
Stakeholder disengagement and
oppositional activism. Loss of social
license, leading to project delays or
stoppages.
Recruitment and retention risk.
ESG investing affects availability and cost
of capital.
Insurance premiums increase. Potential
for classes of assets and locations to
become uninsurable.
Capital cost increases if new
environmental standards require more
expensive supplies relative to alternatives.
Carbon pricing adopted across
jurisdictions, or inconsistently between
them.
Changes to price and cost forecasts
result in stranded assets or reserves.
To increased frequency and intensity of
extreme weather events such as storms,
flooding, coastal inundation, lack of water
availability, or slips.
Offshore drilling and production delayed
or shut in by increased weather events.
Global reduction in high carbon sources
such as coal is increasing demand for
natural gas as a lower carbon partner to
renewables.
s, m, l. Manage environmental performance.
Due diligence screening of commercial
opportunities and joint ventures.
s, m, l.
s, m, l.
m, l.
s, m, l.
s, m, l.
Shadow price on carbon to sensitivity
testing in investment decisions.
Due diligence screening of commercial
opportunities and joint venture processes.
Assurance relating to insurance forecasts.
Access to a range of funding options.
Reporting on climate related governance,
strategy, risks and targets.
Jurisdictional diversification to avoid
impact of sudden, unilateral changes,
confiscation or value destruction by
regulation.
m, l.
Engineering anticipates environmental
conditions.
Carbon policy provides for review of
climate issues in strategic and operational
decisions.
s, m, l.
Strategic preference for natural gas.
Support for our joint venture partners
pursuing low carbon innovations on sites.
5. MEASUREMENTS AND TARGETS
TCFD CATEGORY
RECOMMENDATION
SUMMARISED IN
THIS DOCUMENT AT
Targets and Metrics
Disclose the metrics and targets used to assess and
manage relevant climate-related risks and opportunities
where such information is material.
Disclose the metrics used by the organisation to
assess climate related risks and opportunities in line
with its strategy and risk management process.
Disclose Scope 1, Scope 2 and, if appropriate, Scope
3 greenhouse gas emissions, and the related risks.
Describe the targets used by the organisation to manage
climate-related risks and opportunities and performance
against targets.
4.2
4
5.1.
The company does not report
Scope 3 emissions as the
information does not exist.
5.2, 5.3
The TCFD recommends disclosure of
»
»
»
the measures we use to assess climate-related risks and measure them,
emissions (by Scope 1, 2 and 3), and
the targets that we use to manage climate-related risk.
Measures used to assess risks and measures them are described in section 4, above.
Scope 1 and 2 emissions are disclosed below in Table 5.1. Scope 1 and 2 emissions relate to Cue’s corporate office
activities and emissions from production facilities in New Zealand, Australia and Indonesia. The Company does not
report Scope 3 emissions as the information is not obtainable from end users, and reporting would double count
emissions across the economies in which we operate.
24
TASKFORCE ON CLIMATE–RELATED FINANCIAL
DISCLOSURES (TCFD) STATEMENT
30 JUNE 2022
5.1 METRICS
Total Greenhouse Gas emissions
Corporate office
An annual estimate is prepared of carbon emissions from corporate activity, using inputs such as electricity bills, air
travel and rental car use. The company purchases trees to offset these emissions.
Oil and gas production
Emissions from producing oil and gas fields are reported below, and include Cue’s share of Scope 1 and scope 2
emissions from operations.
The company makes use of the best information or estimates available for reporting CO2 emissions. Maari and
Sampang PSC field Operators report detailed monthly emissions. Amadeus Basin emissions data for FY22 is not
available due to the timing of the Operator’s NGER reporting. This data will be published by Cue when available.
YEAR TO 30 JUNE 2022
METRIC TONNES CO2e
PREVIOUS YEAR
Sampang
Maari
Mahato
4,094
4,171
440
Amadeus Basin Assets
Not Reported
Jakarta Offices*
Melbourne Office
Total Emissions
Scope 1
Scope 2**
14
7
8,726
8,385
341
4,447
4,622
Not Reported
Not Reported
12
5
9,086
9,069
17
*
**
Cue has a filed warehouse site in East Kalimantan which was not reported in FY21 but has been included in the current year reporting.
Includes Scope 2 emissions from total asset based emissions reported above. In FY2021, Sampang Scope 2 was included in Scope 1.
Scope 2 emissions have increased at Sampang in 2022 due to increased Purchased Electricity; however, Scope 1 Stationary Combustion has decreased as a result.
In FY22, Cue has reduced its emissions intensity (CO2 emissions per barrel of Oil equivalent produced) by
approximately 20% excluding any contribution from Amadeus Basin assets.
CO2 e (t) /boe
produced
Cue Emissions Intensity
0.03
0.025
0.02
0.015
0.01
0.005
0
FY21
FY22
25
TASKFORCE ON CLIMATE–RELATED FINANCIAL
DISCLOSURES (TCFD) STATEMENT
30 JUNE 2022
5.2 OUR RESULTS: TCFD TARGETS FOR 2021-22
The Board Operational Risk and Sustainability Committee annually reviews sustainability targets and performance.
FOCUS AREA
2021-22 TARGET
MEASURED BY
STATUS
Reporting
Continue to report Scope 1 and 2
emissions
Reporting
Finalise TCFD compliance and reporting
Publication in annual report.
Available on website
Publication in annual report.
Available on website
Complete, ongoing
Complete, ongoing
Reporting
Reporting
Maintain TCFD statements and reporting
online and in the 2022 Annual Report.
Publication in annual report.
Available on website
Complete, ongoing
Incorporate Amadeus Basin and Mahato
assets into reporting
Publication in annual report.
Available on website
Complete, ongoing
Policy and Legal
Adopt a discrete climate change policy
Commercial
Undertake analysis of an internal price
on carbon to inform TCFD risk and
commercial decisions by end FY 2022
Publication on website Q1
FY22
Complete, ongoing
Report in 2022
Complete, ongoing
Emissions
reductions
Review potential for material emissions
reductions or offsets from producing sites
Report in 2022
Ongoing support for JV based
based emission reduction
projects.
Emissions
management
Benchmark emissions against comparable
production
Report in 2022
Ongoing assessment of
comparable metrics
Emissions
reductions
Emissions
reductions
Emissions
reductions
Offset emissions from head office and
corporate travel.
Initiate ongoing office sustainability
improvement opportunities.
Report in 2022
Complete, ongoing
Report in 2022
Complete, ongoing
Investigate a carbon emission audit and
reduction plan.
Publicly reported.
Evaluation completed. Audit is not
practical at this time due to ongoing
integration of new Asset data.
5.3 OUR INTENTIONS: TCFD TARGETS FOR FY2022-23
FOCUS AREA
TARGET
IMPACT
MEASURED BY
Reporting
Reporting
Reporting
Continue to report Scope 1
and 2 emissions
Disclosure of risks, impacts
and climate responsiveness
Publication in annual report.
Available on website
Maintain TCFD statements
and reporting online and in the 2022
Annual Report.
Disclosure of risks, impacts
and climate responsiveness
Publication in annual report.
Available on website
Continue to enhance Mahato
emissions collection from Operator
Disclosure of risks, impacts
and climate responsiveness
Publication in annual report.
Available on website
Policy and
Legal
Review climate change policy and
update if necessary
Disclosure of climate strategy
Publication in annual report.
Available on website
Commercial
Apply internal price on carbon to
investment decisions
Management of carbon
pricing risk
Report in 2023
Emissions
reductions
Emissions
reductions
Emissions
reductions
Participate with JV partners to identify
material emissions reductions or
offsets at producing sites
Ongoing mitigation of
emissions
Offset 100% of emissions from head
office and corporate travel.
Net zero from our own
operations
Support office sustainability
improvement opportunities.
Sustained emissions
reductions
Report in 2023
Report in 2023
Report in 2023
The company does not have an emissions reduction target for 2022-23. As a non-operator of our Assets, Cue does
not have control over projects undertaken, but we actively encourage and participate in emissions reduction projects
where agreed by Joint Ventures. Additionally, demand for energy from our producing fields is expected to remain high
over the reporting period. Reductions in emissions would require reductions in energy supply to already-constrained
markets. The Company assess that reducing energy output in the current constrained environment would create new
risks to reputation and regulatory responses to require supply.
26
DIRECTORS’ REPORT
30 JUNE 2022
TH E D IREC TORS
P RE SE NT THE IR
RE P OR T, TOGETHER
WI T H T HE F INA NCIA L
S TATE MENTS, ON
TH E C ONSOLI DATED
E NT ITY (REFERRED
TO H ER EAFTER AS
TH E ‘ CO NSOLID ATED
E NT ITY’) CONSISTING
O F CU E ENE RG Y
RE S OU RCE S LI MITED
(R EF E RRE D TO
HE RE AF TE R AS
TH E ‘ CO MPANY’ OR
‘PA RE NT ENTITY’)
A ND T HE E NTITIES IT
CO N TRO LLE D AT TH E
E ND O F, OR D UR ING,
TH E Y E AR E NDED 30
JU N E 2 0 22.
DIRECTORS
The names of Directors of the Company in office during the year and up to the
date of this report were:
Alastair McGregor
Andrew Jefferies
Peter Hood AO
Richard Malcolm
Rod Ritchie
Samuel Kellner
Marco Argentieri
CHIEF EXECUTIVE OFFICER
Matthew Boyall
CHIEF FINANCIAL OFFICER AND COMPANY SECRETARY
Melanie Leydin
PRINCIPAL ACTIVITIES
The principal activities of the group are petroleum exploration, development
and production.
CORPORATE GOVERNANCE STATEMENT
Details of the Company’s corporate governance practices are included in
the Corporate Governance Statement set out on the Company’s website at:
https://www.cuenrg.com.au/site/About-Us/corporate-directory.
DIVIDENDS
There were no dividends paid, recommended or declared during the current
or previous financial year.
27
DIRECTORS’ REPORT
30 JUNE 2022
FINANCIAL PERFORMANCE
Production revenue for the period was $44.44 million, an increase of $21.99 million from the previous period (30
June 2021: $22.45 million). This was mainly attributable to full year of production from the Mahato PSC, generating
revenue of $14.92 million for FY2022 (FY2021: $2.42 million) and the acquisition of the Amadeus Basin business
generating $8.21 million in production revenues from the date of acquisition on 1 October 2021. Production costs of
$18.86 million for the year were $8.20 million higher than the previous period (30 June 2021: $10.66 million), primarily
increasing in the Mahato PSC and the Amadeus Basin which incurred $3.57 million and $5.67 million in production
costs, respectively. This was offset by a reduction of production costs at Maari of $0.50 million to $4.55 million due to
a build-up of inventories at 30 June 2022.
The net assets of the consolidated entity increased by $18.02 million to $47.94 million for the year ended 30 June
2022 (2021: $29.92 million).
Working capital, being current assets less current liabilities, was $17.72 million (30 June 2021: $20.06 million)
The consolidated cash and cash equivalents of the Group as at 30 June 2022 were $23.22 million, an increase of
$5.58 million from $17.64 million, including restricted cash of $0.03 million, at 30 June 2021, primarily due to $12.52
million of expenditure incurred on settlement of obligations to Central Petroleum on completion of the Amadeus Basin
acquisition, offset by net cash inflows from operations of $18.63 million and $6.90 million in proceeds from borrowings
received in June 2022.
The consolidated entity has $7.0 million in borrowings due to New Zealand Oil & Gas (NZOG) Limited, the Company’s
majority shareholder, at 30 June 2022.
Refer to the Operations and Financial Review preceding this Director’s Report for further details.
SIGNIFICANT CHANGES IN THE STATE OF AFFAIRS
On 23 July 2021, the Consolidated Entity issued 4,599,003 options over fully paid ordinary shares for an exercise price
of $0.078 (7.8 cents) per fully paid ordinary share, with an expiry date of 22 July 2026.
On 1 October 2021, the Consolidated Entity, in conjunction with NZOG, the Company’s majority shareholder,
completed the acquisition of interests in the Mereenie, Palm Valley and Dingo gas and oil fields in the Northern
Territory, Australia, from Central Petroleum Limited (ASX: CTP) (Central).
The Consolidated entity’s acquired interests are:
»
»
»
7.5% interest in the Mereenie gas and oil field (OL4 and OL5 Production Licences)
15% interest in the Palm Valley gas field (OL3 Production Licence)
15% interest in the Dingo gas field (L7 Production Licence).
All three fields are in production and supply gas into the Eastern Australia gas market or local Northern Territory
market. As of 30 June 2022, Cue reported 4.1 million barrels of oil equivalent (mmboe) 2P reserves in the fields.
The Consolidated Entity acquired the aforementioned interests for total consideration of $18.8 million, being the
contractually agreed price of $20.7 million less $1.9 million in respect of agreed adjustments, refer to note 33 to
the financial statements for further details. The total consideration comprised of an initial payment of $9.6 million to
Central and deferred consideration, the provisional fair value of which was measured at $9.2 million at 1 October 2021.
On 24 June 2022, the Consolidated Entity entered into a $7 million unsecured loan with NZOG, accruing interest at
10% per annum, in accordance with which it drew down $6.90 million, net of loan establishment costs, in June 2022.
This agreement was executed in order to support the Consolidated Entity’s existing exploration and development
activities and ensure sufficient working capital remains available during expected periods of high expenditure in the
near future. NZOG is a related party, holding 50.04% of shares in the Consolidated Entity.
There were no other significant changes in the state of affairs of the consolidated entity during the financial year.
28
DIRECTORS’ REPORT
30 JUNE 2022
MATTERS SUBSEQUENT TO THE END OF THE FINANCIAL YEAR
In July 2022, the Operator, Central Petroleum, and its Palm Valley and Dingo Joint Venture partners NZOG and the
Consolidated Entity, announced that the drilling program at Palm Valley and Dingo would be revised to defer the Dingo
well and evaluate the lower P2/P3 unit of the Pacoota Sandstone formation (P2/P3) instead of the Deep exploration
target at Palm Valley to prioritise near term production into a very strong East Coast gas market.
On 22 August 2022, the Palm Valley Joint Venture announced the decision to curtail further drilling in the lower P2
and P3 side track. This was due to the combination of the presence of formation water and no significant gas shows.
Total exploration costs of $2.2 million have been incurred in respect of this section of the well. In accordance with the
Group’s accounting policy $1.0 million was expensed in the year ended 30 June 2022, the remainder will be expensed
in the 2023 financial year.
No other matter or circumstance has arisen since 30 June 2022 that has significantly affected, or may significantly
affect the consolidated entity’s operations, the results of those operations, or the consolidated entity’s state of affairs
in future financial years.
LIKELY DEVELOPMENTS AND EXPECTED RESULTS OF OPERATIONS
The following activities may affect the expected results of operations:
» Results from the drilling on the Palm Valley 12 well (PV-12) in the Amadeus Basin and any subsequent drilling;
» Progress on Paus Biru and the Final Investment Decision;
»
»
»
»
»
Further development drilling in the Mahato PSC;
Changes in New Zealand legislation and the impact it may have on the scope and funding of the Maari field’s
decommissioning obligations;
Potential changes in the Maari partnership and the potential this has for a change in the strategic development of
the Maari field;
The short and medium term impact of the Ukrainian conflict on the global energy markets; and
Actively seeking to acquire new production opportunities.
The Coronavirus/Covid-19 global pandemic presents strategic, operational and commercial uncertainties for the
Company. There are increased uncertainties around the duration, scale and impact of the Coronavirus/Covid-19
outbreak, its impact on global supply chains and challenges in the labour markets. As countries emerge from the
effects of the pandemic, there is a significant uncertainty as to the continued government support and longer-term
impact of the pandemic on the global economy.
The Russian-Ukrainian conflict also continues to develop, the result of which have had significant global macro-
economic impacts, including energy prices. Related impacts include volatility in commodity prices and currencies,
supply-chain and travel disruptions, disruption in banking systems and capital markets, increased costs and
expenditures and cyberattacks.
The Board and management team continue to assess the potential impacts on the business, however given the
continued uncertainties the future financial impact, if any, cannot be determined.
29
DIRECTORS’ REPORT
30 JUNE 2022
ENVIRONMENTAL REGULATION
Within the last year there have been zero incidents, zero lost time injuries and zero significant spills within Cue Energy
Resources Limited. Among the joint operations there have been a number of minor incidents that have been reported
and investigated by all the relevant parties. Cue Energy Resources Limited continues to monitor the progress of
reported incidents and work with the joint operation partners and operators to improve overall health and safety and
minimise any impact on the environment.
INFORMATION ON DIRECTORS
Name:
Title:
Qualifications:
Experience and expertise:
Alastair McGregor
Non-Executive Chairman
BEng, MSc
Mr McGregor has been actively involved in the oil and gas sector since 2003.
He is currently chief executive of O.G. Energy, which holds Ofer Global’s
broader energy interests, and Oil & Gas Limited, a company that holds
directly or indirectly oil & gas exploration and production interests onshore
and offshore. He leads the O.G. Energy Senior Management Committee,
driving the strategy for Ofer Global’s energy activities. Mr McGregor is also
a director of NZOG. In addition, Mr McGregor is chief executive of Omni
Offshore Terminals Limited, a leading provider of floating, production, storage
and offloading (FSO and FPSO) solutions to the offshore oil and gas industry.
Omni’s operations have spanned the globe from New Zealand, Australia,
Southeast Asia, Middle East and South America. Prior to entering the oil and
gas industry Mr McGregor spent 12 years as a banker with Citigroup and
Salomon Smith Barney. Mr McGregor holds a BEng from Imperial College,
London and an MSc from Cranfield University in the UK.
Other current directorships:
Former directorships (last 3 years): None
Special responsibilities:
New Zealand Oil & Gas Limited
Member, Remuneration and Nomination Committee
Interests in shares:
Interests in options:
None
None
30
DIRECTORS’ REPORT
30 JUNE 2022
INFORMATION ON DIRECTORS (CONTINUED)
Name:
Title:
Qualifications:
Experience and expertise:
Andrew Jefferies
Non-Executive Director
BE Hons (Mechanical), MBA, MSc in petroleum engineering, GAICD,
Certified Petroleum Engineer
Mr Jefferies is managing director of NZOG. He started his career with Shell
in Australia after graduating with a BE Hons (Mechanical) from the University
of Sydney in 1991, an MBA in technology management from Deakin
University in Australia, and an MSc in petroleum engineering from Heriot -
Watt University in Scotland. Mr Jefferies is also a graduate of the Australian
Institute of Company Directors (GAICD), and a Certified Petroleum Engineer
with the Society of Petroleum Engineers. He has worked in oil and gas in
Australia, Germany, the United Kingdom, Thailand and Holland.
Other current directorships:
Former directorships (last 3 years): None
Special responsibilities:
NZOG Offshore Limited, New Zealand Oil & Gas Limited
Member, Audit and Risk Committee
Member, Remuneration and Nomination Committee
Member, Operational Risk and Sustainability Committee
Member, Commercial Committee
Interests in shares:
Interests in options:
8,000 fully paid ordinary shares
None
Name:
Title:
Experience and expertise:
Peter Hood AO
Non-Executive Director
Mr Hood is a professional chemical engineer with 50 years’ experience in
the development of projects in the resources and chemical industries. He
began his career with WMC Ltd and then was chief executive officer of
Coogee Chemicals Pty Ltd and Coogee Resources Ltd from 1998 to 2009.
He is a graduate of the Harvard Business School Advanced Management
Programme and is currently Chairman of Matrix Composites and Engineering
Ltd and a Non-Executive Director of GR Engineering Ltd and a Non-
Executive Director of De Grey Mining Ltd. He has been Vice-Chairman of
the Australian Petroleum Production and Exploration Association Limited
(APPEA), Chairman of the APPEA Health Safety and Operations Committee,
and is a past President of the Western Australian and Australian Chambers of
Commerce and Industry.
Other current directorships:
De Grey Mining Ltd
GR Engineering Ltd
Matrix Composites and Engineering Ltd
Former directorships (last 3 years): None
Special responsibilities:
Member, Audit and Risk Committee
Member, Commercial Committee
Interests in shares:
Interests in options:
80,000 fully paid ordinary shares
None
31
DIRECTORS’ REPORT
30 JUNE 2022
INFORMATION ON DIRECTORS (CONTINUED)
Name:
Title:
Experience and expertise:
Richard Malcolm
Non-Executive Director
Mr Malcolm is a professional geoscientist with over 40 years of varied oil and
gas experience within seven international markets including Australia/NZ/
PNG, UK North Sea/West of Shetlands, Gulf of Mexico and the Middle East/
North Africa.
His latter roles from 2006 to 2013 included Managing Director of OMV UK
and Managing Director of Gulfsands Petroleum, an AIM listed exploration and
production company with operations in Syria, Tunisia, Morocco, USA and
Colombia.
He is currently a Non-executive Director of Larus Energy Limited.
Other current directorships:
Former directorships (last 3 years): Puravida Energy NL
Special responsibilities:
Larus Energy Limited
Chairman, Remuneration and Nomination Committee
Member, Operational Risk and Sustainability Committee
Interests in shares:
Interests in options:
300,000
None
Name:
Title:
Qualifications:
Experience and expertise:
Rod Ritchie
Non-Executive Director
B.Sc
Mr Ritchie is a director of NZOG. Mr Ritchie joined NZOG’s board in 2013.
He began his career as a petroleum engineer with Schlumberger for 28 Years
and then joined OMV where he worked for a further 12 years. Mr Ritchie
has over 40 years of global experience in leadership roles and as a Health,
Safety, Environmental and Security (HSSE) executive in the Oil and Gas
industry, including being the corporate Senior Vice President of HSSE and
Sustainability at OMV based in Vienna, Austria. He has also worked closely
with the International Association of Oil and Gas produces (IOGP) to create
Industry best practice standards for the Oil and Gas Industry. He is also
an active leadership and cultural change consultant, and an author on the
subject of Safety Leadership and several Society of Petroleum Engineers
papers on the subject of HSSE and safety Leadership.
Other current directorships:
Former directorships (last 3 years): None
Special responsibilities:
New Zealand Oil & Gas Limited
Member, Remuneration and Nomination Committee Chair,
Operational Risk and Sustainability Committee
Interests in shares:
Interests in options:
None
None
32
DIRECTORS’ REPORT
30 JUNE 2022
INFORMATION ON DIRECTORS (CONTINUED)
Name:
Title:
Qualifications:
Experience and expertise:
Samuel Kellner
Non-Executive Director
BA, MBA
Mr Kellner has held a variety of senior executive positions with Ofer Global
since joining the group in 1980. He has been deeply involved in all Ofer
Global’s business lines, with a particular emphasis on offshore oil and
gas, shipping and real estate, and has advised Ofer Global companies
on investments with a variety of investment managers, hedge funds and
private equity funds. Most recently, Mr Kellner served as President of Global
Holdings Management Group (US) Inc. where he led North American real
estate acquisition, development and financing activities. Mr Kellner serves as
a director of O.G. Energy, O.G. Oil & Gas and NZOG, where he is Chairman of
the Board of Directors. As a member of the O.G. Energy Senior Management
Committee, he helps drive strategy for Ofer Global’s energy activities. He
is also an Executive Director of the main holding companies for the Zodiac
Maritime Limited shipping group and Omni Offshore Terminals Limited, a
leading provider of floating, production, storage and offloading (FSO and
FPSO) solutions to the offshore oil and gas industry. Mr Kellner graduated
with a BA degree from Hebrew University in Jerusalem. He has an MBA from
the University of Toronto and taught at the University of Toronto while working
toward a PhD in Applied Economics.
Other current directorships:
O.G. Energy Holdings Ltd.
O.G. Oil & Gas Limited
New Zealand Oil & Gas Limited
Former directorships (last 3 years): None
Special responsibilities:
Member, Audit and Risk Committee
Interests in shares:
Interests in options:
None
None
Name:
Title:
Experience and expertise:
Mr Marco Argentieri
Non-Executive Director
Mr Argentieri is a Director of NZOG, Senior Vice President and General
Counsel for O.G. Energy, and a member of the Board of Directors of both
O.G. Energy and O.G. Oil & Gas. Prior to O.G. Energy, Mr Argentieri worked
extensively in finance, offshore oil services and shipping. Mr Argentieri started
his career as an attorney at the New York offices of Skadden, Arps, Slate,
Meagher & Flom LLP and Latham & Watkins LLP. He holds a B.A. from the
University of Rochester, a J.D. from New York University and an MBA from
Columbia University.
Other current directorships:
Former directorships (last 3 years): None
Special responsibilities:
New Zealand Oil & Gas Limited
Chair, Audit and Risk Committee Member,
Commercial Committee
Interests in shares:
Interests in options:
None
None
‘Other current directorships’ quoted above are current directorships for listed entities only and excludes directorships
of all other types of entities, unless otherwise stated.
‘Former directorships (last 3 years)’ quoted above are directorships held in the last 3 years for listed entities only and
excludes directorships of all other types of entities, unless otherwise stated.
33
DIRECTORS’ REPORT
30 JUNE 2022
COMPANY SECRETARY
Ms Melanie Leydin, BBus (Acc. Corp Law) CA FGIA
Melanie Leydin holds a Bachelor of Business majoring in Accounting and Corporate Law. She is a member of the
Institute of Chartered Accountants, Fellow of the Governance Institute of Australia and is a Registered Company
Auditor. She graduated from Swinburne University in 1997, became a Chartered Accountant in 1999 and from
February 2000 to October 2021 was the principal of Leydin Freyer. In November 2021, Vistra acquired Leydin Freyer
and, Melanie is now Vistra Australia’s Managing Director. Vistra is a prominent provider of expert advisory and
administrative support to Fund, Corporate, Capital Market and Private Wealth clients.
Melanie has over 25 years’ experience in the accounting profession and over 15 years’ experience holding Board
positions including Company Secretary of ASX listed entities. She has extensive experience in relation to public
company responsibilities, including ASX and ASIC compliance, control and implementation of corporate governance,
statutory financial reporting, reorganisation of Companies and shareholder relations.
MEETINGS OF
DIRECTORS
Alastair McGregor
Andrew Jefferies
Peter Hood
Richard Malcolm
Rod Ritchie
Samuel Kellner
Marco Argentieri
FULL BOARD
REMUNERATION AND
NOMINATION COMMITTEE
AUDIT AND RISK
COMMITTEE
OPERATIONAL RISK AND
SUSTAINABILITY
COMMITTEE
ATTENDED
HELD
ATTENDED
HELD
ATTENDED
HELD
ATTENDED
HELD
4
4
4
4
4
4
4
4
4
4
4
4
4
4
1
1
-
1
1
-
-
1
1
-
1
1
-
-
-
2
2
-
-
2
-
-
2
2
-
-
2
-
-
4
-
4
4
-
-
-
4
-
4
4
-
-
Held: represents the number of meetings held during the time the director held office or was a member of the relevant committee.
The Board formed a Commercial Committee on 28 October 2021 consisting of Non-Executive Directors being Peter
Hood, Marco Argentieri and Andrew Jefferies to delegate aspects of commercial decision making to the Committee.
The responsibilities of the Committee include working with and through the management team to progress commercial
opportunities to a state that they can be brought for final investment decision to the full Board. The Commercial
Committee further has authority to approve contractual matters and Petroleum Sales.
34
DIRECTORS’ REPORT
30 JUNE 2022
REMUNERATION REPORT (AUDITED)
This Remuneration Report which has been audited, and which forms part of the Directors’ Report, sets out information
about the remuneration of Cue Energy Resources Limited’s Directors and its senior management for the financial year
ended 30 June 2022, in accordance with the Corporations Act 2001 and its regulations.
Key management personnel (KMP) are those persons having authority and responsibility for planning, directing and
controlling the activities of the entity, directly or indirectly, including all directors.
The prescribed details for each person covered by this report are detailed below under the following headings:
»
»
»
»
»
(A) Director and executive details
(B) Remuneration policy
(C) Details of remuneration
(D) Equity based remuneration
(E) Relationship between remuneration policy and company performance
(A) Director and executive details
The following persons acted as Directors of the company during or since the end of the financial year:
» Alastair McGregor (Non-Executive Chairman)
» Andrew Jefferies (Non-Executive Director)
» Peter Hood (Non-Executive Director)
» Richard Malcolm (Non-Executive Director)
» Rod Ritchie (Non-Executive Director)
» Samuel Kellner (Non-Executive Director)
» Marco Argentieri (Non-Executive Director)
Unless otherwise stated the persons named above held their current position for the whole of the financial year and
since the end of the financial year.
The term “Executive” is used in this Remuneration Report to refer to the following persons:
» Matthew Boyall (Chief Executive Officer)
35
DIRECTORS’ REPORT
30 JUNE 2022
(B) Remuneration policy
The Board’s policy for remuneration of Executives and Directors is detailed below.
Remuneration packages are set at levels that are intended to attract and retain high calibre directors and employees
and align the interest of the Directors and Executives with those of the company’s shareholders. The Remuneration
policy is established and implemented solely by the Board.
Remuneration and other terms and conditions of employment are reviewed annually by the Board having regard to
performance and relevant employment market information. As well as a base salary, remuneration packages include
superannuation, termination entitlements and fringe benefits.
The Board is conscious of its responsibilities in relation to the performance of the Company. Directors and Executives
are encouraged to hold shares in the Company to align their interests with those of shareholders.
No remuneration or other benefits are paid to Directors or Executives by any subsidiary companies.
(C) Details of remuneration
The structure of Non-Executive Director and Executive remuneration is separate and distinct.
Non-Executive Directors
Remuneration of Non-Executive Directors is determined by the Board within the maximum amount approved by
the shareholders from time to time. The amount currently approved is $700,000, which was approved at the Annual
General Meeting held on 24 November 2011. The Company’s policy is to remunerate Non-Executive Directors at a
fixed fee based on their time involvement, commitment and responsibilities. Remuneration for Non-Executive Directors
is not linked to individual or company performance, however, to align Directors’ interests with shareholders’ interests,
Non-Executive Directors are encouraged to hold shares in the Company. The Board retains the discretion to award
options or performance rights to Non-Executive Directors based on the recommendation of the Board, which is always
subject to shareholder approval.
Alastair McGregor, Andrew Jefferies, Samuel Kellner and Marco Argentieri have elected not to be paid by the
Company.
Executives
Executives receive a mixture of fixed and variable pay and a blend of short and long term incentives as appropriate.
Remuneration packages contain the following key elements:
»
Fixed compensation component inclusive of base salary, superannuation and non-monetary benefits
» Short term incentive (STI) programme
»
Long term employee benefits
Fixed compensation
Fixed compensation consists of base salary (which is calculated on a total cost base and including any fringe benefits
tax (“FBT’) charges related to employee benefits including motor vehicles), as well as employer contributions to
superannuation funds.
The base salary is reflective of market rates for companies of similar size and industry which is reviewed annually to
ensure market competitiveness. The Board last reviewed the salaries paid to peer company executives in determining
the salary of the Company’s KMP at the end of the 2021 financial year. This base salary is fixed remuneration and is
not subject to performance of the company. Base salary is reviewed annually and adjusted on 1 July each year as
required. There is no guaranteed base salary increase included in any executive’s contracts.
36
DIRECTORS’ REPORT
30 JUNE 2022
Cash bonuses
A cash bonus was paid to the CEO during this financial year on the achievement of his annual STI, based on actual
performance against key performance indicators (KPIs).
Employment contracts
Remuneration and other terms of employment for key executive Matthew Boyall is formalised in a service agreement.
Details of the agreement is as follows:
Chief Executive Officer
Matthew Boyall
Title:
Original Agreement effective from 1 July 2017, with salary terms revised on 5 July 2021.
Term:
Details:
Permanent employment contract, no fixed terms.
Base salary of $370,800 per annum plus superannuation to be reviewed annually by the Board. Mr
Boyall is also entitled to short-term incentive up to 30% (2021: 30%) of his base salary at the discretion
of the Board at the end of each financial year dependent on the success of meeting key deliverables.
Notice period: 3 months
Compensation levels are reviewed each year to take into account cost of living changes, any change in the scope of
the role performed and any changes to meet the principles of the compensation policy.
Details of the nature and amount of each major element of remuneration of each Director of the Company and other
Key Management Personnel of the consolidated entity are:
KMP Compensation - 2022
SHORT-TERM BENEFITS
LONG-TERM
BENEFITS
POST-
EMPLOYMENT
SHARE-BASED
PAYMENTS
2022
CASH SALARY
AND FEES
CASH
BONUSES
LONG SERVICE
LEAVE
SUPER-
ANNUATION
EQUITY-
SETTLED
TOTAL
$
$
$
$
$
$
DIRECTORS
Alastair McGregor*
Andrew Jefferies*
Peter Hood
Richard Malcolm
Rod Ritchie
Samuel Kellner*
Marco Argentieri*
OTHER KEY
MANAGEMENT
PERSONNEL
Matthew Boyall**
-
-
64,473
59,932
66,000
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
6,527
6,068
-
-
-
-
-
-
-
-
-
-
-
-
71,000
66,000
66,000
-
-
366,868
557,273
73,085
73,085
9,606
9,606
27,500
40,095
61,175
61,175
538,234
741,234
*
**
Alastair McGregor, Andrew Jefferies, Samuel Kellner and Marco Argentieri have elected not to be paid by the Company.
Matthew Boyall’s cash bonus consists of $73,085 for achieving 65.7% weighting against 2021 key performance indicators (KPIs). The KPIs were measured against the
actual results for the calendar year ending 31 December 2021. Mr Boyall is entitled to up to 30% of base salary in short term incentives.
37
DIRECTORS’ REPORT
30 JUNE 2022
KMP Compensation - 2021
SHORT-TERM
BENEFITS
LONG-TERM
BENEFITS
POST-
EMPLOYMENT
SHARE-BASED
PAYMENTS
2021
CASH SALARY
AND FEES
CASH
BONUSES
LONG
SERVICE
LEAVE
SUPER-
ANNUATION
EQUITY-
SETTLED
TOTAL
$
$
$
$
$
$
DIRECTORS
Alastair McGregor*
Andrew Jefferies*
Peter Hood
Richard Malcolm
Rod Ritchie
Samuel Kellner*
Marco Argentieri*
OTHER KEY
MANAGEMENT
PERSONNEL:
Matthew Boyall**
-
-
45,610
43,330
47,500
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
4,390
4,170
-
-
-
-
-
-
-
-
-
-
-
-
50,000
47,500
47,500
-
-
356,694
493,134
64,260
64,260
5,218
5,218
25,000
33,560
62,693
62,693
513,865
658,865
*
**
Alastair McGregor, Andrew Jefferies, Samuel Kellner and Marco Argentieri have elected not to be paid by the Company.
Matthew Boyall’s cash bonus consists of $64,260 for achieving 59.5% weighting against 2020 key performance indicators (KPIs). The KPIs were measured against the
actual results for the calendar year ending 31 December 2020. Mr Boyall is entitled to up to 30% of base salary in short term incentives.
The proportion of remuneration linked to performance and the fixed proportion are as follows:
NAME
DIRECTORS
Peter Hood
Richard Malcolm
Rod Ritchie
OTHER KEY
MANAGEMENT
PERSONNEL:
Matthew Boyall
FIXED REMUNERATION
AT RISK - STI
AT RISK - LTI
2022
2021
2022
2021
2022
2021
100%
100%
100%
100%
100%
100%
-
-
-
-
-
-
-
-
-
-
-
-
75%
75%
14%
13%
11%
12%
(D) Equity based remuneration
Overview of share options
The Board in their meeting held on 24 June 2019 approved the Employee Share Option Plan (‘ESOP’), which was
subsequently approved by shareholders at 2019 Annual General Meeting.
The ESOP has been developed to provide the greatest possible flexibility in choice to the Board in implementing the
executive incentive schemes. The ESOP enables the Board to offer employees a number of Options.
38
DIRECTORS’ REPORT
30 JUNE 2022
A summary of material terms of the ESOP is set out as follows:
»
»
»
»
»
»
»
»
the ESOP sets out the framework for the offer of Options by the Company, and is typical for a document of this
nature;
in making its decision to issue Options, the Board may decide the number of securities and the vesting conditions
which are to apply in respect of the securities. The Board has flexibility to issue Options having regard to a range of
potential vesting criteria and conditions;
in certain circumstances, unvested Options will immediately lapse and any unvested Shares held by the participant
will be forfeited if the relevant person is a “bad leaver” as distinct from a “good leaver”;
if a participant acts fraudulently or dishonestly or is in breach of their obligations to the Company or its
subsidiaries, the Board may determine that any unvested Options held by the participant immediately lapse and
that any unvested Shares held by the participant be forfeited;
in certain circumstances Options can vest early upon a change of control event as defined under the Plan rules;
the total number of Options and Shares which may be offered by the Company under these Rules shall not at any
time exceed 5% of the Company’s total issued Shares when aggregated with the number of Options and Shares
issued or that may be issued as a result of offers made at any time during the previous three year period under an
employee incentive scheme;
the Board has discretion to impose restrictions (except to the extent prohibited by law or the ASX Listing Rules)
on Shares issued or transferred to a participant on vesting of an Option or a Performance Right, and the Company
may implement appropriate procedures to restrict a participant from so dealing in the Shares; and
the Board is granted a certain level of discretion under the Employee Incentive Programme (EIP), including the
power to amend the rules under which the EIP is governed and to waive vesting conditions, forfeiture conditions or
disposal restrictions.
The options will vest on the date determined by the Board and as specified in the Invitation Letter.
4,599,003 options were granted under the ESOP during the financial year to 30 June 2022 (2021: 3,743,260).
1,607,360 options were forfeited due to an employee departure from the Company during the year. These options did
not have any other vesting conditions other than continuing employment and time.
Share-based compensation
Issue of shares
There were no shares issued to directors and other key management personnel as part of compensation during the
year ended 30 June 2022.
Options
The terms and conditions of each grant of options over ordinary shares affecting remuneration of KMP in this financial
year or future reporting years are as follows:
NAME
NUMBER OF
OPTIONS
GRANTED
GRANT DATE
VESTING
DATE AND
EXERCISABLE
DATE
EXPIRY DATE
EXERCISE
PRICE (CENTS)
FAIR VALUE
PER OPTION
AT GRANT
DATE (CENTS)
Matthew Boyall
1,288,338
29 July 2019
1 July 2021
1 July 2023
Matthew Boyall
1,399,595
4 October 2019
1 July 2022
1 July 2024
Matthew Boyall
1,102,607
16 July 2020
1 July 2023
1 July 2025
Matthew Boyall
1,428,843
23 July 2021
1 July 2024
22 July 2026
7.00
9.00
11.70
7.80
4.00
5.90
5.10
3.90
Options granted carry no dividend or voting rights.
39
DIRECTORS’ REPORT
30 JUNE 2022
(E) Relationship between remuneration policy and company performance
Company performance review
The tables below set out summary information about the company’s earnings and movements in shareholder wealth
and key management remuneration for the five years to 30 June 2022.
2022
$’000
2021
$’000
2020
$’000
2019
$’000
2018
$’000
Production revenue from continuing operations
44,439
22,449
23,916
25,730
24,547
Profit/(loss) before income tax expense from
continuing operations
Profit/(loss) after income tax expense
Total KMP remuneration
21,278
(7,290)
16,068
(12,743)
741
659
5,099
1,313
690
12,856
8,549
651
5,058
7,739
525
Share price at start of year (cents)
Share price at end of year (cents)
Basic earnings/(loss) per share (cents)
Diluted earnings/(loss) per share (cents)
2022
2021
2020
2019
2018
6.00
6.50
2.30
2.30
9.50
6.00
(1.83)
(1.83)
8.30
9.50
0.19
0.19
5.70
8.30
1.22
1.22
5.50
5.70
1.11
1.11
The Company remuneration policy also seeks to reward staff members on achieving non-financial key performance
indicators, including safety and operational performance.
Additional disclosures relating to key management personnel
Shareholding
The number of shares in the company held during the financial year by each director and other members of key
management personnel of the consolidated entity, including their personally related parties, is set out below:
BALANCE AT THE
START OF THE
YEAR
ADDITIONS
DISPOSALS/
OTHER
BALANCE AT THE
END OF THE YEAR
ORDINARY SHARES*
NON-EXECUTIVE DIRECTORS
Andrew Jefferies
Peter Hood
Richard Malcolm**
OTHER KEY MANAGEMENT
PERSONNEL:
Matthew Boyall
8,000
80,000
-
200,000
288,000
-
-
300,000
-
300,000
-
-
-
-
-
8,000
80,000
300,000
200,000
588,000
*
Alastair McGregor, Rod Ritchie, Samuel Kellner and Marco Argentieri do not hold any fully paid ordinary shares.
** Mr Richard Malcolm purchased 300,000 shares on market on 6 September 2021 as disclosed to the ASX.
40
DIRECTORS’ REPORT
30 JUNE 2022
NZOG Offshore Limited (a related entity to Alastair McGregor, Andrew Jefferies, Rod Richie, Samuel Kellner and Marco
Argentieri) holds 349,368,803 fully paid ordinary shares in the Company.
Option holding
The number of options over ordinary shares in the company held during the financial year by each director and other members
of key management personnel of the consolidated entity, including their personally related parties, is set out below:
BALANCE AT THE
START OF THE
YEAR
GRANTED
EXERCISED
EXPIRED/
FORFEITED/
OTHER
BALANCE AT THE
END OF THE YEAR
Options over ordinary shares
Matthew Boyall
3,790,540
1,428,843
3,790,540
1,428,843
-
-
-
-
5,219,383
5,219,383
This concludes the remuneration report, which has been audited.
SHARES UNDER OPTION
Unissued ordinary shares of Cue Energy Resources Limited under option at the date of this report are as follows:
GRANT DATE
EXPIRY DATE
VESTING DATE
EXERCISE
PRICE (CENTS)
NUMBER
UNDER
OPTION
29/07/2019
01/07/2023
01/07/2021
04/10/2019
01/07/2024
01/07/2022
16/07/2020
01/07/2025
01/07/2023
23/07/2021
22/07/2026
01/07/2024
7.00
9.00
11.70
7.80
3,513,430
3,569,764
3,241,067
4,047,966
No person entitled to exercise the options had or has any right by virtue of the option to participate in any share issue
of the company or of any other body corporate.
SHARES ISSUED ON THE EXERCISE OF OPTIONS
There were no ordinary shares of Cue Energy Resources Limited issued on the exercise of options during the year
ended 30 June 2022 and up to the date of this report.
DIRECTORS’ INSURANCE AND INDEMNIFICATION OF DIRECTORS AND AUDITORS
During the financial year, the company paid a premium in respect of a contract insuring the directors of the company,
the company secretary, and all executive officers against a liability incurred as a director, company secretary or
executive officer to the extent permitted by the Corporations Act 2001. In accordance with commercial practice, the
insurance policy prohibits disclosure of the terms of the policy, including the nature of the liability insured against and
the amount of the premium.
The company has not otherwise, during or since the end of the financial year indemnified or agreed to indemnify the
auditor of the company or any related body corporate against a liability incurred as an officer or auditor.
PROCEEDINGS ON BEHALF OF THE COMPANY
No person has applied to the Court under section 237 of the Corporations Act 2001 for leave to bring proceedings on
behalf of the company, or to intervene in any proceedings to which the company is a party for the purpose of taking
responsibility on behalf of the company for all or part of those proceedings.
41
DIRECTORS’ REPORT
30 JUNE 2022
NON-AUDIT SERVICES
Details of the amounts paid or payable to the auditor for non-audit services provided during the financial year by the
auditor are outlined in note 27 to the financial statements.
The Company may decide to employ the auditor on assignments additional to its statutory audit duties where the
auditor’s expertise and experience with the Company are important.
The Board of Directors has considered the position and 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, did not compromise the audit
independence requirement, of the Corporations Act 2001, based on advice received from the Audit and Risk
Committee, for the following reasons:
»
»
all non-audit services have been reviewed and approved to ensure that they do not impact the integrity and
objectivity of the auditor; and
none of the services undermine the general principles relating to auditor independence as set out in APES 110
Code of Ethics for Professional Accountants issued by the Accounting Professional and Ethical Standards Board,
including reviewing or auditing the auditor’s own work, acting in a management or decision-making capacity for
the company, acting as advocate for the company or jointly sharing economic risks and rewards.
OFFICERS OF THE COMPANY WHO ARE FORMER PARTNERS OF KPMG
There are no officers of the company who are former partners of KPMG.
ROUNDING OF AMOUNTS
The Company is a company of the kind referred to in ASIC Legislative Instrument 2016/191, and in accordance with
the Class Order amounts in the Directors’ Report and the Financial Report are rounded off to the nearest thousand
dollars, unless otherwise indicated.
AUDITOR’S INDEPENDENCE DECLARATION
A copy of the auditor’s independence declaration as required under section 307C of the Corporations Act 2001 is set
out immediately after this directors’ report and forms part of the directors’ report.
AUDITOR
In accordance with the provisions of the Corporations Act 2001 the Company’s auditor, KPMG, continues in office.
This report is made in accordance with a resolution of directors, pursuant to section 298(2)(a) of the Corporations Act
2001.
On behalf of the Board
Alastair McGregor
Non-Executive Chairman
25 August 2022
42
AUDITOR’S INDEPENDENCE DECLARATION
30 JUNE 2022
Lead Auditor’s Independence Declaration under
Section 307C of the Corporations Act 2001
To the Directors of Cue Energy Resources Limited
I declare that, to the best of my knowledge and belief, in relation to the audit of Cue Energy Resources
Limited for the financial year ended 30 June 2022 there have been:
i.
ii.
no contraventions of the auditor independence requirements as set out in the Corporations
Act 2001 in relation to the audit; and
no contraventions of any applicable code of professional conduct in relation to the audit.
KPM_INI_01
KPMG
Vicky Carlson
Partner
Melbourne
25 August 2022
KPMG, an Australian partnership and a member firm of the KPMG global organisation of independent member firms affiliated
with KPMG International Limited, a private English company limited by guarantee. All rights reserved. The KPMG name and logo
are trademarks used under license by the independent member firms of the KPMG global organisation. Liability limited by a
scheme approved under Professional Standards Legislation.
43
STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME
FOR THE YEAR ENDED 30 JUNE 2022
Revenue from continuing operations
Revenue from operations
Production costs
Gross profit from production
Other income
Net foreign currency exchange gain / (loss)
Expenses
Exploration and evaluation expenses
Administration expenses
Finance costs
Profit/(loss) before income tax expense
Income tax expense
NOTE
CONSOLIDATED
2022
$’000
2021
$’000
5
6
7
8
9
44,439
18,856
25,583
15
10
(1,560)
(3,029)
259
21,278
(5,210)
22,449
10,665
11,784
220
(2,550)
(12,843)
(3,834)
(67)
(7,290)
(5,453)
Profit/(loss) after income tax expense for the year attributable
to the owners of Cue Energy Resources Limited
16,068
(12,743)
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Foreign currency translation
Other comprehensive income for the year, net of tax
Total comprehensive income for the year attributable
to the owners of Cue Energy Resources Limited
Basic earnings/(loss) per share
Diluted earnings/(loss) per share
1,759
1,759
(1,085)
(1,085)
17,827
(13,828)
CENTS
CENTS
36
36
2.30
2.30
(1.83)
(1.83)
The above statement of profit or loss and other comprehensive income should be read in conjunction with the accompanying notes
44
STATEMENT OF FINANCIAL POSITION
AS AT 30 JUNE 2022
ASSETS
Current assets
Cash and cash equivalents
Restricted cash
Trade and other receivables
Inventories
Total current assets
Non-current assets
Other financial assets
Property, plant and equipment
Right-of-use assets
Exploration and evaluation assets
Production properties
Development assets
Deferred tax asset
Total non-current assets
Total assets
LIABILITIES
Current liabilities
Trade and other payables
Contract liabilities
Lease liabilities
Tax liabilities
Provisions
Deferred consideration
Total current liabilities
Non-current liabilities
Contract liabilities
Borrowings
Lease liabilities
Deferred tax liability
Provisions
Total non-current liabilities
Total liabilities
Net assets
EQUITY
Contributed equity
Reserves
Accumulated losses
Total equity
NOTE
CONSOLIDATED
2022
$’000
2021
$’000
10
10
11
12
13
14
15
16
17
18
9
19
18
20
9
21
22
24
23,223
17,617
-
8,740
1,237
27
7,342
437
33,200
25,423
6,300
5,784
34
175
1,950
54,117
4,243
6,888
73,707
106,907
4,651
1,545
86
2,666
192
6,337
44
194
-
18,344
3,670
2,641
30,677
56,100
2,960
-
52
2,115
232
-
15,477
5,359
5,207
6,895
122
6,751
24,517
43,492
58,969
47,938
-
-
145
5,017
15,656
20,818
26,177
29,923
152,416
152,416
1,132
(815)
(105,610)
(121,678)
47,938
29,923
The above statement of financial position should be read in conjunction with the accompanying notes
45
STATEMENT OF CHANGES IN EQUITY
FOR THE YEAR ENDED 30 JUNE 2022
CONSOLIDATED
CONTRIBUTED
EQUITY
$’000
RESERVES
$’000
ACCUMULATED
LOSSES
$’000
TOTAL EQUITY
$’000
Balance at 1 July 2020
152,416
Loss after income tax expense for the year
Other comprehensive loss for the year, net of tax
Total comprehensive loss for the year
Transactions with owners in their capacity as owners:
Share-based payments (note 37)
Balance at 30 June 2021
-
-
-
-
152,416
83
-
(1,085)
(1,085)
187
(815)
(108,935)
43,564
(12,743)
(12,743)
-
(1,085)
(12,743)
(13,828)
-
187
(121,678)
29,923
CONSOLIDATED
CONTRIBUTED
EQUITY
$’000
RESERVES
$’000
ACCUMULATED
LOSSES
$’000
TOTAL EQUITY
$’000
Balance at 1 July 2021
152,416
(815)
(121,678)
Profit after income tax expense for the year
Other comprehensive income for the year, net of tax
Total comprehensive income for the year
Transactions with owners in their capacity as owners:
Share-based payments (note 37)
Balance at 30 June 2022
-
-
-
-
-
16,068
1,759
1,759
-
16,068
29,923
16,068
1,759
17,827
188
-
188
152,416
1,132
(105,610)
47,938
The above statement of changes in equity should be read in conjunction with the accompanying notes
46
STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED 30 JUNE 2022
Cash flows from operating activities
Receipts from customers
Other receipts
Interest received
Payments to suppliers and employees
Payments for exploration and evaluation expenditure
Income tax paid
Royalties paid
Interest and other finance costs paid
NOTE
CONSOLIDATED
2022
$’000
2021
$’000
43,548
18,575
-
11
538
25
(16,472)
(10,541)
(1,885)
(12,186)
(7,274)
(4,185)
(261)
(256)
17,667
(8,030)
(5)
-
Net cash from/(used in) operating activities
35
17,662
(8,030)
Cash flows from investing activities
Payments with respect to exploration,
development and production properties
Payments for plant and equipment
Payment for businesses acquired
Net cash used in investing activities
Cash flows from financing activities
Payments of principal element of lease liabilities
Proceeds from borrowings, net of fees
Net cash from/(used in) financing activities
Net increase/(decrease) in cash and cash equivalents
Cash and cash equivalents at the beginning of the financial year
Effects of exchange rate changes on cash and cash equivalents and restricted cash
Cash and cash equivalents at the end of the financial year
The above statement of cash flows should be read in conjunction with the accompanying notes
(6,588)
(3,510)
(5)
33
(12,522)
(7)
-
(19,115)
(3,517)
20
10
(48)
6,895
6,847
5,394
(84)
-
(84)
(11,631)
17,644
31,944
185
23,223
(2,669)
17,644
47
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 1.
GENERAL INFORMATION
The financial statements cover Cue Energy Resources Limited as a consolidated entity consisting of Cue Energy
Resources Limited and the entities it controlled at the end of, or during, the year. The financial statements are
presented in Australian dollars, which is Cue Energy Resources Limited’s functional and presentation currency.
Cue Energy Resources Limited is a listed public company limited by shares, incorporated and domiciled in Australia,
whose shares are publicly traded on the Australian Securities Exchange.
A description of the nature of the consolidated entity’s operations and its principal activities are included in the
directors’ report, which is not part of the financial statements.
The financial statements were authorised for issue, in accordance with a resolution of directors, on 25 August 2022.
NOTE 2.
SIGNIFICANT ACCOUNTING POLICIES
Significant accounting policies have been disclosed in the respective notes to the financial statements and below.
(a) Operations and principal activities
Operations comprise petroleum exploration, development and production activities.
(b) Statement of compliance
The financial report is a general purpose financial report presented in Australian dollars which has been prepared in
accordance with Australian Accounting Standards and Interpretations issued by the Australian Accounting Standards
Board (“AASB”) and the Corporations Act 2001, as appropriate for for-profit oriented entities. International Financial
Reporting Standards (“IFRSs”) form the basis of Australian Accounting Standards adopted by the AASB. The financial
reports of the consolidated entity also comply with IFRS and interpretations adopted by the International Accounting
Standards Board.
The accounting policies set out below have been applied consistently to all periods presented in this report.
(c) Basis of preparation
The Group is of a kind referred to in ASIC Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191
and in accordance with that instrument, amounts in the consolidated financial statements and directors’ report have
been rounded off to the nearest thousand dollars, unless otherwise stated.
The consolidated financial statements has been prepared on a going concern basis using the historical
cost convention.
In accordance with the Corporations Act 2001, these financial statements present the results of the consolidated entity
only. Supplementary information about the parent entity is disclosed in note 30.
(d) Principles of consolidation
The consolidated financial statements incorporate the assets and liabilities of all subsidiaries of Cue Energy Resources
Limited (‘’company’’ or ‘’parent entity’’) as at 30 June 2022 and the results of all subsidiaries for the year then ended.
Cue Energy Resources Limited and its subsidiaries together are referred to in this financial report as the Group or
consolidated entity.
Subsidiaries are all those entities over which the Group has control. The consolidated entity controls an entity when it
is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect these
returns through its power to direct the activities of the entity. The existence and effect of potential voting rights that are
currently exercisable or convertible are considered when assessing whether the Group controls another entity.
Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are de-
consolidated from the date that control ceases.
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.
Investments in subsidiaries are accounted for at cost in the individual financial statements of Cue Energy
Resources Limited.
48
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 2.
SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(e) Production revenue
The consolidated entity generates production revenue from its interest in producing crude oil and gas fields. Revenue
from oil production is recognised at a point in time when crude oil is delivered to the buyer. Oil contract price is
negotiated when the operator lifts for the group. Revenue from gas production in Indonesia is recognised during
the month when gas is delivered to the buyer, based on fixed price contracts and in Australia on the basis of both
contractually defined prices and spot gas market pricing.
All oil and gas revenues are recognised at a single point in time.
(f) Inventories
Inventories consist of hydrocarbon stock. Inventories are valued at the lower of cost and net realisable value. Cost
is determined on a weighted average basis and includes direct costs and an appropriate portion of fixed production
overheads where applicable.
(g) Comparative figures
When required by Accounting Standards, comparative figures have been adjusted to conform to changes in
presentation for the current financial year.
(h) Finance costs
Finance costs attributable to qualifying assets are capitalised as part of the asset. All other finance costs are expensed
in the period in which they are incurred.
(i) Goods and Services Tax (‘GST’) and other similar taxes
Revenues, expenses and assets are recognised net of the amount of associated GST, unless the GST incurred is not
recoverable from the tax authority. In this case it is recognised as part of the cost of the 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 tax authority is included in other receivables or other 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 tax authority, are presented as operating cash flows.
Commitments and contingencies are disclosed net of the amount of GST recoverable from, or payable to, t
he tax authority.
(j) Foreign currency
Functional and presentation currency
The functional currencies of Group companies is the currency of the primary economic environment in which it
operates. The consolidated financial statements are presented in Australian dollars, as this is the Group’s presentation
currency.
Transactions and balances
Transactions in foreign currencies of entities within the consolidated entity are translated into functional currency at the
rate of exchange ruling at the date of the transaction. Non-monetary items measured at historical cost continue to be
carried at the exchange rate at the date of the transaction. Non-monetary items measured at fair value are reported at
the exchange rate at the date when fair values were determined.
Foreign currency monetary items that are outstanding at the reporting date (other than monetary items arising under
foreign currency contracts where the exchange rate for that monetary item is fixed in the contract) are translated using
the spot rate at the end of financial year.
Exchange differences arising on the translation of non-monetary items are recognised directly in other comprehensive
income to the extent that the underlying gain or loss is recognised in other comprehensive income; otherwise the
exchange difference is recognised in profit or loss.
49
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 2.
SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Foreign operations
The results and financial position of Cue’s foreign operations are translated into its presentation currency using the
following procedures:
(a) assets and liabilities for each statement of financial position presented (i.e. including comparatives) shall be
translated at the closing rate at the date of that statement of financial position;
(b) income and expenses for each statement presenting profit or loss and other comprehensive income (i.e. including
comparatives) shall be translated at average exchange rates for the year; and
(c) all resulting exchange differences shall be recognised in other comprehensive income.
(k) New or amended Accounting Standards and Interpretations adopted
The Consolidated Entity has adopted all of the new or amended Accounting Standards and Interpretations issued by
the Australian Accounting Standards Board (‘AASB’) that are mandatory for the current reporting period. There was no
impact upon adoption of these standards.
Any new or amended Accounting Standards or Interpretations that are not yet mandatory have not been early
adopted.
NOTE 3.
CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS
The preparation of a financial report in conformity with Australian Accounting Standards requires management to
make judgements, estimates and assumptions that affect the application of policies and reported amounts of assets
and liabilities, income and expenses. The estimates and associated 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 judgement about carrying values of assets and liabilities that are not readily apparent from
other sources. Actual results may differ from these estimates. These accounting policies have been consistently
applied by each entity in the consolidated entity, and the estimates and underlying assumptions are reviewed on an
ongoing basis.
The judgements, estimates and assumptions that have a significant risk of causing a material adjustment to the
carrying values of assets and liabilities within the next financial year are discussed below.
(i) Recovery of deferred tax assets
Deferred tax assets are only recognised if management considers it is probable that future tax profits will be available
to utilise the unused tax losses (refer to note 9). There are inherent uncertainties in the various assumptions used
estimation of future generation of taxable income, particularly in respect of project development and energy prices,
which are subject to global macroeconomic factors which can materially impact the future estimations of taxable
income against which carried forward tax losses may be utilised.
(ii) Impairment of production properties
Production properties impairment testing requires an estimation of recoverable amount, which management have
determined using a value-in-use model for respective cash generating units. The recoverable amount calculation
requires the entity to estimate the future cash flows expected to arise from the cash generating unit and a suitable
discount rate in order to calculate present value. Other assumptions used in the calculations which could have an
impact on future years includes USD rates, available reserves and oil and gas prices (refer to note 14).
(iii) Useful life of production properties
As detailed at note 14 production properties are amortised on a unit-of-production basis, with separate calculations
being made for each resource. Estimates of reserve quantities are a critical estimate impacting amortisation of
production property assets.
50
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 3.
CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS (CONTINUED)
(iv) Estimates of reserve quantities
The estimated quantities of Proven and Probable hydrocarbon reserves reported by the Company are integral to the
calculation of the amortisation expense relating to Production Property Assets, and to the assessment of possible
impairment of these assets. Estimated reserve quantities are based upon interpretations of geological and geophysical
models and assessments of the technical feasibility and commercial viability of producing the reserves. These
assessments require assumptions to be made regarding future development and production costs, commodity prices,
exchange rates and fiscal regimes. The estimates of reserves may change from period to period as the economic
assumptions used to estimate the reserves can change from period to period, and as additional geological data is
generated during the course of operations. Reserves estimates are prepared in accordance with the Company’s policies
and procedures for reserves estimation which conform to guidelines prepared by the Society of Petroleum Engineers.
(v) Restoration provisions
Provisions for future environmental restoration are recognised where there is a present obligation as a result of
exploration, development, production, transportation or storage activities having been undertaken, and it is probable
that an outflow of economic benefits will be required to settle the obligation. The estimated future obligations include
the costs of removing facilities, abandoning wells and restoring the affected areas in accordance with the terms of
the respective permits and relevant legislation in the various jurisdictions in which the Consolidated Entity operates
There is inherent uncertainty in the definition of the works undertaken, technology used to complete the works,
the estimation of the relevant costs associated with the defined works and the timing of settlement of restoration
obligations. Details of restoration provisions are disclosed in note 21.
(vi) Capitalised exploration and evaluation costs
Exploration and evaluation costs have been capitalised on the basis that the consolidated entity expects to
commence commercial production in the future, from which time the costs will be amortised in proportion to the
depletion of the mineral resources. Key judgements are applied in considering costs to be capitalised which includes
determining expenditures directly related to these activities and allocating overheads between those that are expensed
and capitalised. In addition, costs are only capitalised that are expected to be recovered either through successful
development or sale of the relevant mining interest. Factors that could impact the future commercial production at the
mine include the level of reserves and resources, future technology changes, which could impact the cost of mining,
future legal changes and changes in commodity prices. To the extent that capitalised costs are determined not to be
recoverable in the future, they will be written off in the period in which this determination is made.
(vii) Contract liabilities
There are inherent uncertainties in estimating the expected liability in relation to performance obligations for take or
pay arrangements and the future provision of service. These include the fair value of gas to be provided and the timing
that the customer will take their remaining entitlements. The carrying value of these obligations is reflected in note 18.
(viii) Coronavirus (COVID-19) pandemic
In March 2020, the World Health Organization declared the outbreak of a novel coronavirus (COVID-19) as a pandemic,
which continues to have a significant impact globally as well as in Australia. The spread of COVID-19 continues to cause
significant volatility in Australian and international markets, there continuing to be significant uncertainty around the breadth
and duration of business disruptions related to COVID-19. At the date of this report, the impact of these measures is not
expected to significantly affect the Company’s business operations, although management cannot reliably measure the
extent to which such measures will impact the Consolidated Entity’s financial position and performance.
(viiii) Russian-Ukrainian conflict
The Russian-Ukrainian conflict continues to develop, the result of which have had significant global macro-economic
impacts, including increasing instability in global energy prices. Related impacts include volatility in commodity
prices, currency movements, supply-chain and travel disruptions, disruption in banking systems and capital markets,
increased costs and expenditures and cyberattacks. At the date of this report, the conflict has had the effect of
increasing crude oil and natural gas prices, offset to some extent by the inflationary effect on the Australian and other
economies. This has however, on an overall basis, been a positive impact on the Consolidated Entity’s results from
operations.
The conflict’s development and conclusion is inherently uncertain and the consequences for the global economy and
the Company’s operations unpredictable. The Company has, to the extent possible, in assessing the carrying value of
its assets and liabilities, reflected the impact which the conflict has and has on its financial position and performance.
51
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 4.
FINANCIAL REPORTING BY SEGMENTS
Segment Information
AASB 8 requires operating segments to be identified on the basis of internal reports about components of the Group
that are regularly reviewed and used by the Board of Directors (who are identified as the Chief Operating Decision
Makers (“CODM”)) in assessing performance and in determining the allocation of resources.
The CODM assesses the performance of the operating segments based upon a measure of earnings before interest
expense, tax, depreciation and amortisation. The accounting policies adopted for internal reporting to the CODM are
consistent with those adopted in the Group financial statements.
The Group operates in three principle geographic segments: Australia, New Zealand and Indonesia. Furthermore,
with the acquisition of the Amadeus business, it has been concluded more appropriate to present corporate
activities separate from other operations in Australia, consistent with internal reporting. For presentation purposes,
comparatives have been represented accordingly.
Australia
The parent entity resides in Melbourne, Australia. The Group, through its wholly owned subsidiary, Cue Exploration Pty
Ltd, and through separate legal entities, holds 3 permits in the Amadeus Basin in the Northern Territory. For details of
subsidiaries refer to note 31 and interests in joint operations refer to note 32.
New Zealand
The Group, through its wholly owned subsidiary, Cue Taranaki Pty Ltd, holds 5% interest in petroleum production
property, PMP38160 (Maari) in New Zealand.
Indonesia
The Group, through its wholly owned subsidiary, Cue Sampang Pty Ltd, holds a 15% interest in the Sampang
PSC gas production property and through Cue Mahato Pty Ltd, a 12.5% interest in the Mahato PSC oil production
property. The Group also holds interests in exploration permit Mahakam Hilir PSC, which has expired and is in the
process of surrender.
Information regarding the Group’s reportable segments is presented below:
CONSOLIDATED - 2022
Revenue
Revenue from operations
Total revenue
EBITDAX
Depreciation and amortisation
Business development expenses
Finance costs
Share-based payments
Exploration and evaluation expenses
Profit/(loss) before income tax expense
Income tax expense
Profit after income tax expense
AUSTRALIA
$’000
NEW
ZEALAND
$’000
INDONESIA
$’000
CORPORATE
$’000
TOTAL
$’000
8,208
8,208
4,116
(1,590)
(654)
(79)
-
(1,469)
324
9,169
9,169
5,987
(1,371)
-
266
-
-
27,062
27,062
20,883
(2,468)
-
83
(9)
(91)
-
-
(1,949)
(68)
(119)
(11)
(179)
-
4,882
18,398
(2,326)
44,439
44,439
29,037
(5,497)
(773)
259
(188)
(1,560)
21,278
(5,210)
16,068
52
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 4.
FINANCIAL REPORTING BY SEGMENTS (CONTINUED)
30 JUNE 2022
SEGMENT ASSETS
Current assets
Non-current assets
Total assets
SEGMENT LIABILITIES
Current liabilities
Non-current liabilities
Total liabilities
CONSOLIDATED - 2021
Revenue
Revenue from operations
Total revenue
EBITDAX
Depreciation and amortisation
Business development expenses
Finance costs
Exploration and evaluation expenses
Share-based payments expense
One off settlement expenses
AUSTRALIA
$’000
NEW
ZEALAND
$’000
INDONESIA
$’000
CORPORATE
$’000
ELIMI-
NATIONS
$’000
TOTAL
$’000
1,830
36,053
37,883
5,055
58,530
63,585
1,055
16,262
17,317
991
24,919
25,910
9,111
20,450
29,561
3,279
41,301
44,580
21,204
90,133
111,337
6,152
6,964
13,116
-
(88,222)
(88,222)
-
(88,222)
(88,222)
33,200
74,676
107,876
15,477
43,492
58,969
AUSTRALIA
$’000
NEW
ZEALAND
$’000
INDONESIA
$’000
CORPORATE
$’000
TOTAL
$’000
-
-
(1,322)
-
(165)
(3)
(12,283)
-
-
6,945
6,945
3,476
(1,432)
-
(64)
-
-
-
15,504
15,504
11,464
(1,372)
-
-
(560)
(40)
-
9,492
-
-
(3,200)
(76)
(606)
-
-
(139)
(968)
(4,989)
22,449
22,449
10,418
(2,880)
(771)
(67)
(12,843)
(179)
(968)
(7,290)
(5,453)
(12,743)
Profit/(loss) before income tax expense
(13,773)
1,980
Income tax expense
Loss after income tax expense
30 JUNE 2021
SEGMENT ASSETS
Current assets
Non-current assets
Total assets
SEGMENT LIABILITIES
Current liabilities
Non-current liabilities
Total liabilities
Major customers
AUSTRALIA
$’000
NEW
ZEALAND
$’000
INDONESIA
$’000
CORPORATE
$’000
ELIMI-
NATIONS
$’000
TOTAL
$’000
27
-
27
643
317
960
2,989
13,049
16,038
1,109
28,677
29,786
7,044
17,413
24,457
2,568
48,256
50,824
15,363
56,705
72,068
1,039
58
1,097
-
(56,490)
(56,490)
-
(56,490)
(56,490)
25,423
30,677
56,100
5,359
20,818
26,177
The Group has a number of customers to whom it provides oil products, of which 58% (2021: 25%) of revenue
is supplied to one customer and 36% (2021:73%) to the other. The Group supplies gas to a number of external
customers, one of which generates 63% (2021:100%) of revenue and 13% (2021:0%) to the other.
53
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 5.
REVENUE FROM OPERATIONS
Revenue from operations
Disaggregation of revenue
The disaggregation of revenue from contracts with customers is as follows:
Natural gas revenue
Crude oil and condensate revenue
NOTE 6.
PRODUCTION COSTS
Production costs
Amortisation of production properties
CONSOLIDATED
2022
$’000
2021
$’000
44,439
22,449
18,723
12,940
25,716
9,509
44,439
22,449
CONSOLIDATED
2022
$’000
2021
$’000
13,441
5,415
7,861
2,804
18,856
10,665
NOTE 7.
EXPLORATION AND EVALUATION EXPENSES
Accounting policy for exploration and evaluation project expenditure
AASB 6 Exploration for and Evaluation of Mineral Resources allows the Group to either capitalise or expense the
exploration and evaluation expenditure incurred. During the financial year the consolidated entity reviewed its criteria
under its successful efforts method of accounting. The costs of a successful exploration well are capitalised and
carried forward as exploration and evaluation assets pending the evaluation of the success of the well (refer note 13).
If a well does not result in a successful discovery, the previously capitalised costs are immediately expensed.
Profit/(loss) before income tax includes the following specific (reversal)/expenses:
Exploration costs (reversed)/expensed
Sampang PSC
Mahakam Hilir PSC
WA-359-P
WA-389-P
WA-409-P
Mereenie
Palm Valley
Dingo
CONSOLIDATED
2022
$’000
2021
$’000
-
90
29
490
(447)
11,998
11
27
29
1,835
15
268
58
-
-
-
Exploration costs expensed
1,560
12,843
54
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 7.
EXPLORATION AND EVALUATION EXPENSES (CONTINUED)
The Consolidated Entity incurred $0.87 million of expenses in respect of the discontinued exploration works on the
Palm Valley Deep well and $0.97 million of expenses in respect of with the side track targeting the lower P2 and P3
reservoirs.
Exploration activities continue, the objective of which is to exploit the Palm Valley P1 resource target within the well
infrastructure.
A credit to exploration expenses of $0.45 million was recognised in the year ended 30 June 2022, arising from the
reversal of prior period accrued Ironbark expenses.
NOTE 8.
ADMINISTRATION EXPENSES
Employee expenses
Business development expenses
Accounting and audit fees
Share based payments
Superannuation contribution expense
Depreciation expense
Legal expenses*
Other expenses
Total administration expenses
CONSOLIDATED
2022
$’000
2021
$’000
1,308
1,170
773
371
188
71
82
19
217
3,029
771
329
179
74
76
1,032
203
3,834
* This figure for the year ended 30 June 2021 included:
* $0.50 million (US$0.38 million) associated with the settlement of the dispute between Cue and the Mahato PSC joint operation partners.
$0.46 million (US$0.35 million) associated with the settlement of the Hammerhead litigation in relation to the Pine Mills oilfield.
55
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 9.
INCOME TAX
During the year ended 30 June 2020, Cue was notified that it had been successful in an Indonesian Tax Court case
CONSOLIDATED
Income tax expense
Current tax
Adjustment recognised for current tax in prior periods
Deferred tax - origination and reversal of temporary differences (i)
Aggregate income tax expense
Numerical reconciliation of income tax expense and tax at the statutory rate
Profit/(loss) before income tax expense
Tax at the statutory tax rate of 30%
Tax effect amounts which are not deductible/(taxable) in calculating taxable income:
Unrealised foreign exchange movements
Unrecognised temporary differences
Unrecognised tax losses
Recognition of deferred tax (assets)/liabilities (ii)
Difference in overseas tax rates
Share-based payments
Other balances and permanent differences
Prior year tax losses not recognised/(recognised)
Adjustment recognised for current tax in prior periods
Income tax expense
(i) Deferred tax included in income tax expense comprises:
Decrease/(increase) in deferred tax assets
Increase/(decrease) in deferred tax liabilities
Deferred tax - origination and reversal of temporary differences
2022
$’000
2021
$’000
7,424
299
(2,513)
5,210
21,278
6,383
(5)
13
301
(2,513)
2,833
56
(2,636)
479
4,911
299
5,210
4,474
(228)
1,207
5,453
(7,290)
(2,187)
809
(10)
3,642
1,207
1,865
42
313
-
5,681
(228)
5,453
CONSOLIDATED
2022
$’000
2021
$’000
(4,247)
1,734
(2,513)
247
960
1,207
During the year ended 30 June 2020, Cue was notified that it had been successful in an Indonesian Tax Court case
against the Indonesian Tax Department for over-payment of $0.66 million in taxes relating to 2011, resulting in a partial
refund of $0.45 million which was received in December 2019. The remaining balance was received during the current
period.
(ii) During the prior year, the consolidated entity capitalised Mahato PB exploration wells drilling costs (refer note 14).
As a result, a deferred tax liability of $0.51 million was recognised in the financial statements.
Current tax liabilities
56
CONSOLIDATED
2022
$’000
2021
$’000
2,666
2,115
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 9. INCOME TAX (CONTINUED)
The Group has an ongoing Indonesian Tax matter relating to a notice of amended assessment which is being disputed
by Cue Kalimantan Pte Ltd on behalf of SPC E&P Pte Ltd. Cue is indemnified by SPC for any losses arising from this
disputed notice of assessment and has recognised a liability and receivable on the balance sheet.
Deferred tax asset recognised comprises of:
Restoration provisions
Carried forward tax losses
Other
CONSOLIDATED
2022
$’000
2021
$’000
4,703
1,772
413
6,888
2,641
-
-
2,641
During the year ended 30 June 2022, the Consolidated Entity recognised a deferred tax asset of $1.77 million in
respect of previously unrecognised carried forward tax losses. The Consolidated Entity has a deferred tax asset of
$35.86 million at 30 June 2022 for carried forward tax losses not recognised.
Deferred tax liability recognised comprises of:
Production, development and exploration and evaluation assets
Restoration provision offset
Other
Deferred tax liability
Deferred tax not recognised comprises temporary differences attributable to:
Employee provisions
Tax losses
Less deferred tax liabilities not recognised - Production properties
Less deferred tax liabilities not recognised - Inventories
Accrued expenses
Net deferred tax not recognised
CONSOLIDATED
2022
$’000
2021
$’000
6,768
-
(17)
6,751
5,107
(105)
15
5,017
CONSOLIDATED
2022
$’000
2021
$’000
58
85
39,298
40,611
(3,172)
(1,752)
(360)
36
(122)
-
35,860
38,822
The above net potential tax benefit has not been recognised in the statement of financial position as the recovery of
this benefit is uncertain.
At 30 June 2022 no franking and imputation credits were held for subsequent reporting periods (2021: nil).
57
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 9.
INCOME TAX (CONTINUED)
Accounting policy for Income tax
The income tax expense for the year is the tax payable on the current period’s taxable income based on the applicable
income tax rate for each jurisdiction adjusted by changes in deferred tax assets and liabilities attributable to temporary
differences and to unused tax losses.
Deferred income 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. However, deferred
income tax is 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 reporting
date 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 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.
Current and deferred tax balances attributable to amounts recognised directly in equity are also recognised directly in
equity.
Cue Energy Resources Limited (the ‘head entity’) and its wholly-owned Australian controlled entities have formed an
income tax consolidated group under the tax consolidation regime effective 1 July 2010.
Cue Taranaki Pty Ltd is subject to the provisions of its Petroleum Mining Permit (the Permit) which, in conjunction
with the Minerals Programme for Petroleum (1995) Act and Crown Minerals (Royalties for Petroleum) Regulations
2013 (collectively the Legislation), defines the basis of provisional royalty payments made each reporting period. The
provisions of the Permit define a hybrid royalty system whereby the minimum royalty payment, is the higher of 5% of
revenues or 20% of the provisional accounting profit (APR), as defined in the legislation.
The Consolidated Entity recognises the minimum royalty payment as a royalty expense, included in the statement of
profit or loss and other comprehensive income as production costs, with any excess of the APR over the minimum
royalty payment presented as an income tax expense, in accordance with AASB 112. At 30 June 2022 a deferred tax
asset of $3.54 million and a deferred tax liability of $2.71 million have been recognised in respect of the application
of the terms of the Legislation to timing differences arising between the recognition and measurement criteria in the
Legislation and the application of Australian Accounting Standards. These deferred tax balances are in addition to
balances recognised on temporary timing differences generated through the application of the respective corporate
income tax legislation in the jurisdictions in which the Consolidated Entity operates.
NOTE 10.
CURRENT ASSETS - CASH AND CASH EQUIVALENTS
Unrestricted cash operating accounts
Restricted cash - Ironbark Drilling Program Account*
Total as disclosed in the statement of cash flows
CONSOLIDATED
2022
$’000
2021
$’000
23,223
17,617
-
27
23,223
17,644
*
Restricted cash at 30 June 2021 included cash held by the Company as required under the funding arrangement of the WA-359-P Co-ordination Agreement for the by the
Ironbark drilling program account. The majority of these funds were drawn down over the period to settle exploration expenditure associated with the WA-359.
58
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 10.
CURRENT ASSETS - CASH AND CASH EQUIVALENTS (CONTINUED)
Accounting policy for cash and cash equivalents and restricted cash
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. For the statement of cash flows presentation
purposes, cash and cash equivalents also includes bank overdrafts, which are shown within borrowings in current
liabilities on the statement of financial position.
NOTE 11.
CURRENT ASSETS - TRADE AND OTHER RECEIVABLES
The group applies the AASB 9 simplified approach to measuring expected credit losses which uses a lifetime
expected loss allowance for all trade receivables. To measure the expected credit losses, trade receivables have been
grouped based on shared credit risk characteristics and the days past due.
Trade receivables
Other receivables
Prepayments
Total trade and other receivables
Allowance for expected credit losses
CONSOLIDATED
2022
$’000
2021
$’000
6,344
2,221
8,565
175
8,740
5,205
2,031
7,236
106
7,342
The group applies the AASB 9 simplified approach to measuring expected credit losses which uses a lifetime
expected loss allowance for all trade receivables. To measure the expected credit losses, trade receivables have been
grouped based on shared credit risk characteristics and the days past due.
The consolidated entity has not recognised any losses in profit or loss in respect of the expected credit losses for the
year ended 30 June 2022 (2021: Nil).
The ageing of trade and other receivables at the reporting date was as follows:
Not overdue
Less than one month
CONSOLIDATED
2022
$’000
2021
$’000
4,150
4,415
8,565
2,665
4,571
7,236
Trade and other receivables are not considered impaired and relate to a number of independent customers for whom
there is no recent history of default.
Accounting policy for trade and other receivables
Trade and other receivables are amounts due from customers for goods sold in the ordinary course of business.
They are generally due for settlement within 30 days and therefore are all classified as current. Trade receivables
are recognised initially at the amount of consideration that is unconditional unless they contain significant financing
components, when they are recognised at fair value.
59
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 12.
NON-CURRENT ASSETS - OTHER FINANCIAL ASSETS
Other financial assets is comprised of prepayments made to fund Cue Sampang’s share of rehabilitation obligations.
Prepaid restoration fund - Sampang
CONSOLIDATED
2022
$’000
2021
$’000
6,300
5,784
Cue Sampang contributed $nil to the restoration fund for the Sampang PSC during the year ended 30 June 2022
(2021: $0.53 million), the increase in financial assets being due to the impact of restatement of US Dollar denominated
assets to Australian Dollars.
Accounting policy for other financial assets
Other financial assets are recognised and measured in accordance with AASB Interpretation 5 Rights to Interests
arising from Decommissioning, Restoration and Environmental Rehabilitation Funds (AASBI 5). AASBI 5 requires
restoration provisions and contributions to funds to be separately disclosed in the Consolidated Entity’s statement of
financial position.
NOTE 13. NON-CURRENT ASSETS - EXPLORATION AND EVALUATION ASSETS
Exploration and evaluation costs is comprised of:
Exploration and evaluation - Palm Valley
Exploration and evaluation - Dingo
CONSOLIDATED
2022
$’000
2021
$’000
1,770
180
1,950
-
-
-
Under the recognition and measurement criteria defined in AASB 6 Exploration for and Evaluation of Mineral
Resources, the costs of a successful exploration well are capitalised and carried forward as exploration and evaluation
assets pending the evaluation of the success of the well. If a well does not result in a successful discovery, the
previously capitalised costs are immediately expensed.
As detailed in note 34, in July 2022, the Operator, Central Petroleum Limited, (“Central”) (ASX: CTP) and its Palm Valley
and Dingo Joint Venture partners NZOG and the Consolidated Entity, announced that the drilling program at Palm
Valley and Dingo will be revised to defer the Dingo well and evaluate the lower P2 and P3 side track of the Pacoota
Sandstone formation (P2/P3) instead of the Deep exploration target at Palm Valley to prioritise near term production
into a very strong East Coast gas market.
Furthermore, as detailed in note 34, in August 2022, Central and its Joint Venture partners announced that the drilling
program at the lower P2/P3 unit of the Pacoota Sandstone formation (P2/P3) will cease and further drilling will target
the P1 reservoir in the Palm Valley field.
60
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 14.
NON-CURRENT ASSETS - PRODUCTION PROPERTIES
Net accumulated cost incurred on areas of interest
Joint operation assets
Oyong and Wortel - Sampang PSC
Maari - PMP 38160
Mahato
Palm Valley
Mereenie
Dingo
Balance as at 30 June
Reconciliations
CONSOLIDATED
2022
$’000
2021
$’000
3,820
4,758
13,048
10,408
6,131
3,127
19,762
8,229
54,117
3,178
-
-
-
18,344
Reconciliations of the written down values at the beginning and end of the current and previous financial year are set
out below:
Balance at 1 July
Additions during the year
Changes in restoration provision – production (note 21)
Amortisation expense
Transfer in from development assets**
Additions through Amadeus Basin business combination (note 33)
Changes in foreign currency translation
Closing balance 30 June
CONSOLIDATED
2022
$’000
2021
$’000
18,344
18,682
3,233
2,799
842
(81)
(5,415)
(2,804)
-
3,272
33,609
1,547
54,117
-
(1,567)
18,344
Estimates of recoverable amounts are based on the assets’ value-in-use, determined by discounting each asset’s
estimated future cash flows at asset specific discount rates and based upon the Group’s long term pricing
assumptions. The pre-tax discount rates applied were 14.3% (2021: 14.3%) equivalent to post-tax discount rates of
10.0% (2021: 10.0%) depending on the nature of the risks specific to each asset.
**
Production assets transferred in, relate to Mahato development assets including the PB-1 and PB-2 wells, which were drilled as exploration wells in late 2019 and early
2020. During calendar year 2021, these wells commenced commercial oil production, wells PB-3, PB-4 and PB-5 also being drilled in the year ended 30 June 2021 and
brought into production during the year ended 30 June 2022.
61
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 14.
NON-CURRENT ASSETS - PRODUCTION PROPERTIES (CONTINUED)
Accounting policy for production properties
Production properties are carried at the reporting date at cost less accumulated amortisation and accumulated
impairment losses. Production properties represent the accumulation of all exploration, evaluation, development and
acquisition costs in relation to areas of interest in which production licences have been granted.
Amortisation of costs is provided on the unit-of-production basis, separate calculations being made for each
resource. The unit-of-production basis results in an amortisation charge proportional to the depletion of economically
recoverable reserves (comprising both proven and probable reserves), and is expensed through the statement of profit
or loss and other comprehensive income.
Amounts (including subsidies) received during the exploration, evaluation, development or construction phases which are
in the nature of reimbursement or recoupment of previously incurred costs are offset against such capitalised costs.
Accounting policy for impairment
The carrying amounts of the consolidated entity’s assets are reviewed at each reporting date to determine whether
there is any indication of impairment. If any such indication exists, the asset’s recoverable amount is estimated.
An impairment loss is recognised whenever the carrying amount of an asset or its cash generating unit exceeds the
recoverable amount. Impairment losses are recognised in profit or loss, unless an asset has previously been revalued,
in which case the impairment loss is recognised as a reversal to the extent of that previous revaluation with any excess
recognised through profit or loss.
Impairment losses and reversals are recognised in respect of cash-generating units are allocated to reduce the
carrying amount of the assets in the unit (group of units) on a pro rata basis.
Accounting policy for calculation of recoverable amount
For oil and gas assets the estimated future cash flows are based on value-in-use calculations using estimates of
hydrocarbon reserves, future production profiles, commodity prices, operating costs and any future development
costs necessary to produce the reserves, through 5 years from the reporting date. Estimates of future commodity
prices are based on contracted prices where applicable or based on consensus estimates of forward market prices
where available. The recoverable amount of other assets is the greater of their fair value less cost to dispose and
value-in-use.
In assessing value-in-use, the estimated future cash flows are discounted to their present value using a post-tax
discount rate that reflects current market assessments of the time value of money and the risks specific to the asset.
For an asset that does not generate largely independent cash inflows, the recoverable amount is determined for the
cash-generating unit to which the asset belongs.
The restoration provision is deducted from the carrying value of the asset as the cost of restoration is included in its
cost base. This adjustment is required to allow a true reflection of its carrying value against its recoverable value.
Where an asset does not generate cash flows that are largely independent from other assets or groups of assets, the
recoverable amount is determined for the cash-generating unit to which the asset belongs.
NOTE 15.
NON-CURRENT ASSETS - DEVELOPMENT ASSETS
Sampang Paus Biru
Mereenie
CONSOLIDATED
2022
$’000
2021
$’000
4,185
58
4,243
3,670
-
3,670
As detailed in note 33, on 1 October 2021, the Consolidated Entity acquired the Amadeus business, as a result of
which $0.06 million was incurred post-acquisition on Mereenie development works.
62
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 16.
NON-CURRENT ASSETS - DEFERRED TAX ASSET
Deferred tax asset
CONSOLIDATED
2022
$’000
2021
$’000
6,888
2,641
During the year ended 30 June 2022, the Consolidated Entity recognised a deferred tax asset of $1.77 million in
respect of previously unrecognised carried forward tax losses. The Consolidated Entity has a deferred tax asset of
$35.86 million at 30 June 2022 for carried forward tax losses not recognised.
The Consolidated Entity also recognised $2.0 million of deferred tax assets on acquisition of the Amadeus Basin
business, as detailed in note 33, which has been offset against deferred tax liabilities at 30 June 2022.
NOTE 17.
CURRENT LIABILITIES - TRADE AND OTHER PAYABLES
Trade payables and accruals
Amounts due to directors and director related entities
CONSOLIDATED
2022
$’000
2021
$’000
4,489
162
4,651
2,274
686
2,960
Refer to note 25 for further information on financial instruments.
The Directors consider the carrying amount of payables reflect their fair values.
Accounting policy for trade and other payables
These amounts represent the principal amounts outstanding at the reporting date plus, where applicable, any accrued
interest. Trade payables are normally paid within 30 days, and due to their short term nature are generally unsecured
and not discounted.
NOTE 18.
CONTRACT LIABILITIES
Current
Non-current
CONSOLIDATED
2022
$’000
2021
$’000
1,545
5,207
6,752
-
-
-
Unsatisfied performance obligations
The aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied at the end
of the reporting period was $6.75 million at 30 June 2022 (30 June 2021: nil), of which $1.54 million is expected to be
recognised as revenue within 12 months and $5.21 million to be recognised as revenue in more than 12 months from
the reporting date.
63
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 18.
CONTRACT LIABILITIES (CONTINUED)
Accounting policy for contract liabilities
Contract liabilities represent the consolidated entity’s obligation to transfer gas to customers and are recognised when a
customer pays consideration, or when the consolidated entity recognises a receivable to reflect its unconditional right to
consideration (whichever is earlier) before the consolidated entity has transferred the goods or services to the customer.
Upon acquisition of the Amadeus basin assets, the consolidated entity assumed performance obligations for the
delivery of gas for which payment was received by the operator pre-acquisition. Furthermore, upon acquisition the
consolidated entity assumed the performance obligation for gas not taken by its sole customer in the Dingo field, in
respect of a take or pay arrangement in accordance with which the consolidated entity has the obligation to upon
request provide gas in the contractually defined volumes which were not able to be consumed. The customer must
take the future delivery of gas no later than 2035
NOTE 19.
CURRENT LIABILITIES - DEFERRED CONSIDERATION
Deferred consideration
CONSOLIDATED
2022
$’000
2021
$’000
6,337
-
On 1 October 2021, the Consolidated Entity acquired the Amadeus Basin Business for $18.8 million, being $20.7
million less working capital adjustments of $1.9 million. As detailed in note 33, $9.6 million was paid in cash on
acquisition, the balance expected to be settled within 12 months of the reporting date, primarily in respect of the Palm
Valley exploration and Mereenie development works.
NOTE 20.
NON-CURRENT LIABILITIES - BORROWINGS
Loan from NZOG
CONSOLIDATED
2022
$’000
2021
$’000
6,895
-
The consolidated entity entered into a two-year, unsecured loan agreement with NZOG. The loan is unsecured, with
an interest rate of 10% p.a. fixed for the term of the loan and an establishment fee of 1.5% of the loan amount. The
term of the loan is two years and early repayments are allowed with no penalty and the fair value of the loan at 30 June
2022 is $6.90 million (2021: nil).
Refer to note 25 for further information on financial instruments.
Accounting policy for borrowings
Loans and borrowings are initially recognised at the fair value of the consideration received, net of transaction costs.
They are subsequently measured at amortised cost using the effective interest method.
NOTE 21.
NON-CURRENT LIABILITIES - PROVISIONS
Employee benefits
Restoration provisions
64
CONSOLIDATED
2022
$’000
2021
$’000
-
48
24,517
15,608
24,517
15,656
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 21.
NON-CURRENT LIABILITIES - PROVISIONS (CONTINUED)
Movements in restoration provision during the financial year are set out below:
CONSOLIDATED - 2022
Carrying amount at the start of the year
Change in provisions recognised
Additions through business combinations (note 33)
FX translation
Carrying amount at the end of the year
Accounting policy for provisions
RESTORATION
PROVISIONS
$’000
15,608
918
6,546
1,445
24,517
A provision is recognised in the statement of financial position when the Group has a present legal or constructive
obligation as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be
required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Provisions are
determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments
of the time value of money and, where appropriate, the risk specific to the liability.
Restoration provision
Provisions for future environmental restoration are recognised where there is a present obligation as a result of
exploration, development, production, transportation or storage activities having been undertaken, and it is probable
that an outflow of economic benefits will be required to settle the obligation. The estimated future obligations include
the costs of removing facilities, abandoning wells and restoring the affected areas. The expected timing of outflows for
restoration liabilities is not within 12 months from the reporting date.
The provision of future restoration costs is the best estimate of the present value of the future expenditure required to
settle the restoration obligation at the reporting date, based on current legal requirements. Future restoration costs are
reviewed annually and any changes in the estimate are reflected in the present value of the restoration provision at the
reporting date, with a corresponding change in the cost of the associated asset.
The amount of the provision for future restoration costs relating to exploration, development and production facilities is
capitalised and depleted as a component of the cost of those activities.
Accounting policy for employee benefits
The following liabilities arising in respect of employee benefits are measured at their nominal amounts:
»
»
wages and salaries and annual leave expected to be settled within twelve months of the reporting date; and
other employee benefits expected to be settled within twelve months of the reporting date.
All other employee benefit liabilities expected to be settled more than 12 months after the reporting date are measured
at the present value of the estimated future cash outflows in respect of services provided up to the reporting date.
Liabilities are determined after taking into consideration estimated future increase in wages and salaries and past
experience regarding staff departures. Related on-costs are included.
65
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 22.
EQUITY - CONTRIBUTED EQUITY
CONSOLIDATED
2022
SHARES
2021
SHARES
2022
$’000
2021
$’000
Ordinary shares - fully paid
698,119,720
698,119,720
152,416
152,416
Ordinary shares entitle the holder to the right to receive dividends as declared and, in the event of winding up the
Company, to participate in the proceeds from the sale of all surplus assets in proportion to the number of and amounts
paid on the shares held. Ordinary shares entitle holders to one vote, either in person or by proxy at a meeting of the
Company. The Company has an unlimited authorised capital and the shares have no par value.
Accounting policy for contributed equity
Ordinary share capital is recognised at the fair value of the consideration received by the Company. Any transaction costs
arising on the issue of ordinary shares are recognised directly in equity as a reduction of the share proceeds received.
Ordinary share capital bears no special terms or conditions affecting income or capital entitlements of the shareholders.
NOTE 23.
EQUITY - CAPITAL MANAGEMENT
When managing capital, management’s objective is to ensure the entity continues as a going concern as well as
maintaining optimal return for shareholders and benefits for other stakeholders.
Management will assess the capital structure of the entity to take advantage of favourable costs of capital or high
returns on assets. As the market is constantly changing, management may change the amount of dividends to be paid
to shareholders, return capital to shareholders, or issue new shares.
During 2022 management did not pay any dividends (2021: nil).
There has been no change during the year to the strategy adopted by management to control the capital of the entity.
The gearing ratio is 0.14 for 2022 and nil for 2021.
NOTE 24.
EQUITY - RESERVES
Movements in reserves
Movements in each class of reserve during the current and previous financial year are set out below:
CONSOLIDATED
Balance at 1 July 2020
Foreign currency translation
Share-based payments
Balance at 30 June 2021
Foreign currency translation
Share-based payments
Balance at 30 June 2022
Foreign currency reserve
FOREIGN
CURRENCY
RESERVE
$’000
OPTIONS
RESERVE
$’000
TOTAL
$’000
(93)
(1,085)
-
(1,178)
1,759
-
581
176
-
187
363
-
188
551
83
(1,085)
187
(815)
1,759
188
1,132
The reserve is used to recognise exchange differences arising from the translation of the financial statements of
foreign operations to Australian dollars.
Options reserve
The reserve is used to recognise the value of equity benefits provided to employees under the Employee Share Option Plan.
66
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 25.
FINANCIAL INSTRUMENTS
The Group’s principal financial instruments comprise receivables, payables, cash and cash equivalents (inclusive of
restricted balances).
The Group manages its exposure to key financial risks, including interest rate and currency risk through management’s
regular assessment of financial risks. The objective of the assessment is to support the delivery of the Group’s
financial targets whilst protecting future financial security.
The main risks arising from the Group’s financial instruments are interest rate risk, foreign currency risk, commodity
price risk, credit risk and liquidity risk. The Group uses different methods to measure and manage different types of
risk to which it is exposed. These include monitoring levels of exposure to interest rate and foreign exchange risk
and assessments of market forecasts for interest rates, foreign exchange and commodity prices. These risks are
summarised below.
Ultimate responsibility for liquidity risk management rests with the Board of Directors, who have established an
appropriate liquidity risk management framework for the management of the Group’s short, medium and long-term
funding and liquidity management requirements. The Board reviews and agrees management’s assessment for
managing each of the risks identified below.
In all instances the fair value of financial assets and liabilities approximates to their carrying value.
Risk Exposures and Responses
(a) Fair value risk
The financial assets and liabilities of the Group are recognised in the statement of financial position at their fair value
in accordance with the accounting policies set out in these notes to the financial statements. The Group has trade
receivables, other financial assets and trade payables are a reasonable approximation of their fair values due to their
short-term nature. The Group entered into a $7.0 million loan with NZOG on 24 June 2022, maturing within 2 years of
inception, the fair value of which was estimated at $6.90 million. Given the nature of the financial assets and liabilities
noted and the relatively short term nature and the use of the appropriate interest rates in determining the loan’s fair
value, there is no material fair value risk.
(b) Interest rate risk
The Group’s exposure to market interest rates is related primarily to the Group’s cash deposits.
The Group constantly analyses its interest rate opportunity and exposure. Within this analysis consideration is given to
existing positions and alternative arrangement on fixed or variable deposits. The impact of interest rate movement is
not material to the Group.
(c) Foreign exchange risk
The Group is subject to foreign exchange risk on its international exploration and appraisal activities where costs are
incurred in foreign currencies. The Group generates significant amounts of foreign currencies, however, does not
hold significant foreign currency balances. The Group’s foreign exchange risk exposures are mitigated through natural
hedging, where appropriate.
The Group’s exposure to foreign exchange risk at the reporting date was as follows (holdings are shown in AUD
equivalent):
CONSOLIDATED 30 JUN 2022
Financial assets
Trade and other receivables
Financial liabilities
Trade and other payables
NZD
$’000
IDR
$’000
53
901
7
-
67
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 25.
FINANCIAL INSTRUMENTS (CONTINUED)
CONSOLIDATED 30 JUN 2021
Financial assets
Trade and other receivables
Financial liabilities
Trade and other payables
Tax liabilities
NZD
$’000
IDR
$’000
150
991
-
19
1
13
Management believes the risk exposures as at the reporting date are representative of the risk exposure inherent in the
financial instruments.
(d) Commodity price risk
The Group is involved in oil and gas exploration and appraisal and receives revenue from the sale of hydrocarbons.
Exposure to commodity price risk is therefore limited to this production and from successful exploration and appraisal
activities the quantum of which at this stage cannot be measured.
Gas contracts are primarily fixed, with an immaterial value of contracts subject to spot prices, limiting the Group’s
exposure to fluctuations in gas price.
The Group is exposed to commodity price fluctuations through the sale of petroleum products denominated in US dollars.
Commodity price risks are measured by monitoring and stress testing the Group’s forecast financial position to
sustained periods of low oil and gas prices. This analysis is regularly performed on the Group’s portfolio and, as
required, for discrete projects and acquisitions. At 30 June 2022, there is no material commodity price exposure.
(e) Liquidity risk
Liquidity risk is the risk that the group, although balance sheet solvent, cannot meet or generate sufficient cash
resources to meet its payment obligations in full as they fall due, or can only do so at materially disadvantageous terms.
Ultimate responsibility for liquidity risk management rests with the Board of Directors, who have established an
appropriate liquidity risk management framework for the management of the Group’s short, medium and long-term
funding and liquidity management requirements. The Group manages liquidity risk by maintaining adequate reserves,
banking facilities and by continuously monitoring forecast and actual cash flows and matching the maturity profiles of
financial assets and liabilities.
The Group is consequently able to meet its payment obligations in full as they fall due.
Prudent liquidity risk management implies maintaining sufficient cash to meet the Group’s obligations. The Group aims
to maintain flexibility in funding to meet ongoing operational requirements, exploration and development expenditure,
and small-to-medium-sized opportunistic projects and investments, including taking out loans and where available
and appropriate, maintaining credit facilities.
The following table analyses the contractual maturities of the Group’s financial liabilities into relevant groupings based
on the remaining period at the reporting date to the contractual undiscounted cash flows comprising principal and
interest repayments.
30 JUNE 2022
NON-DERIVATIVE FINANCIAL LIABILITIES
Trade and other payables (note 17)
Lease liabilities
Borrowings
12 MONTHS
OR LESS
$’000
1 TO 2
YEARS
$’000
2 TO 5
YEARS
$’000
MORE THAN
5 YEARS
$’000
4,651
89
630
-
106
7,618
-
17
-
-
-
-
68
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 25.
FINANCIAL INSTRUMENTS (CONTINUED)
30 JUNE 2021
NON-DERIVATIVE FINANCIAL LIABILITIES
12 MONTHS
OR LESS
$’000
1 TO 2
YEARS
$’000
2 TO 5
YEARS
$’000
MORE THAN
5 YEARS
$’000
Trade and other payables (note 17)
Lease liabilities
(f) Credit risk
2,960
39
-
65
-
85
-
-
Credit risk arises from the financial assets of the group, which comprise cash and cash equivalents and restricted
cash and trade and other receivables. The Group’s exposure to credit risk arises from potential default by the counter-
party, with maximum exposure equal to the carrying amount of these instruments. Exposure at the reporting date is
addressed in each applicable note.
The Group does not hold any credit derivatives to offset its credit exposure.
The Group trades only with recognised, creditworthy third parties, and as such collateral is not requested nor is it the
Group’s policy to securitize its trade and other receivables.
It is the Group’s policy that all customers who wish to trade on credit terms are subject to credit verification
procedures which could include an assessment of their independent credit rating, financial position, past experience
and industry reputation. The risks are regularly monitored.
Generally, trade receivables are written off when there is no reasonable expectation of recovery. Indicators of this
include the failure of a debtor to engage in a repayment plan, no active enforcement activity and a failure to make
contractual payments for a period greater than 1 year.
NOTE 26.
KEY MANAGEMENT PERSONNEL DISCLOSURES AND RELATED PARTY DISCLOSURES
Directors
The following persons were directors of Cue Energy Resources Limited during the financial year:
» Alastair McGregor
(Non-executive Chairman)*
» Andrew Jefferies
(Non-Executive Director)*
» Peter Hood AO
(Non-Executive Director)
» Richard Malcolm
(Non-Executive Director)
» Rod Ritchie
(Non-Executive Director)
» Samuel Kellner
(Non-Executive Director)*
» Marco Argentieri
(Non-Executive Director)*
*Alastair McGregor, Andrew Jefferies, Samuel Kellner and Marco Argentieri have elected not to be paid by the Company.
Key management personnel
The following person also had the authority and responsibility for planning, directing and controlling the major activities
of the consolidated entity, directly or indirectly, during the financial year:
» Matthew Boyall (Chief Executive Officer)
Total remuneration payments and equity issued to Directors and key management personnel are summarised below.
Elements of Directors and executives remuneration includes:
» Short term employment benefits, including non-monetary benefits and consultancy fees
» Post-employment benefits – superannuation and long service leave entitlements
»
Long term employee benefits
69
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 26.
KEY MANAGEMENT PERSONNEL DISCLOSURES AND RELATED PARTY DISCLOSURES
(CONTINUED)
Short term employment benefits (including non-monetary benefits)
Cash bonuses
Long term benefits
Post-employment benefits
Share-based payments
Total employee benefits
Other related party transactions
CONSOLIDATED
2022
$
2021
$
557,273
493,134
73,085
64,260
9,606
5,218
40,095
61,175
33,560
62,693
741,234
658,865
Repayment of amounts owing to the Company as at 30 June 2022 and all future debts due to the Company, by
the controlled entities are subordinated in favour of all other creditors. Cue Energy has agreed to provide sufficient
financial assistance to the controlled entities as and when it is needed to enable the controlled entities to continue
operations.
The parent company provides management, administration and accounting services to the subsidiaries.
No management fees were charged to subsidiaries in the 2021 and 2022 financial years.
The ultimate parent company is O.G. Oil & Gas (Singapore) Pte. Ltd., a company incorporated in Singapore.
The immediate parent company is NZOG, a company incorporated in New Zealand.
During the financial year, NZOG provided technical and legal services to the Group under consulting agreements.
The arrangements are on normal commercial terms. As at 30 June 2022, $0.162 million was accrued for services
rendered from the immediate parent company and directors (2021: $0.66 million).
During the financial year, NZOG granted a $7.0 million unsecured loan to the consolidated entity, the details of which
are in note 20.
NOTE 27.
AUDITOR’S REMUNERATION
During the financial year the following fees were paid or payable for services provided by the auditor of the company:
Audit services - KPMG
Audit or review of the financial statements
Other assurance services
Other services - KPMG
Advisory services
Tax compliance
No other services were provided by the auditor during the year, other than those set out above.
70
CONSOLIDATED
2022
$
2021
$
167,360
127,290
8,280
8,280
175,640
135,570
72,036
28,142
100,178
27,955
12,938
40,893
275,818
176,463
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 28.
CONTINGENT ASSETS AND LIABILITIES
The Directors are not aware of any contingent assets or contingent liabilities as at 30 June 2022 (2021: Nil).
NOTE 29.
COMMITMENTS FOR EXPENDITURE
Exploration and evaluation, development and production expenditure commitments*
The Group participates in a number of licences, permits and production sharing contracts for
which the Group has made commitments with relevant governments to complete minimum
work programmes.
Within one year
One to five years
CONSOLIDATED
2022
$’000
2021
$’000
15,728
2,733
878
-
16,606
2,733
*
Exploration expenditure commitments of $2.89 million at 30 June 2022 are in respect of Palm Valley 12 exploration drilling and related works, whilst development and
production expenditure commitments at 30 June 2022 include $0.39 million of Mereenie flare reduction works and $12.95 million of drilling and infrastructure works at the
Mahato PSC.
Commitments reflect the Consolidated Entity’s interest in future financial obligations, based on existing facts
and circumstances, where the Consolidated Entity is contractually or substantively committed to making future
expenditure. These commitments may be either direct obligations or, as is the case with most commitments,
obligations which the respective projects’ operators enter into on the Consolidated Entity’s behalf with suppliers and
service providers.
NOTE 30.
PARENT ENTITY INFORMATION
Cue Energy Resources Limited is the parent entity.
Set out below is the supplementary information about the parent entity.
Statement of profit or loss and other comprehensive income
Loss after income tax
Total comprehensive loss
PARENT
2022
$’000
2021
$’000
(1,939)
(1,939)
(4,588)
(4,588)
71
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 30.
PARENT ENTITY INFORMATION (CONTINUED)
Statement of financial position
Total current assets
Total assets
Total current liabilities
Total liabilities
Equity
Contributed equity
Options reserve
Accumulated losses
Total equity
PARENT
2022
$’000
2021
$’000
21,204
28,497
6,899
13,887
15,363
17,624
1,060
1,263
152,416
152,416
550
363
(138,356)
(136,418)
14,610
16,361
Guarantees entered into by the parent entity in relation to the debts of its subsidiaries
The parent entity had no guarantees in relation to the debts of its subsidiaries as at 30 June 2022 (2021: nil)
Contingent liabilities
The parent entity had no contingent liabilities as at 30 June 2022 (2021: nil)
Capital commitments - Property, plant and equipment
The parent entity had no capital commitments for the acquisition of capital assets as at 30 June 2022 (2021: nil).
NOTE 31.
SHARES IN SUBSIDIARIES
Shares held by parent entity at the reporting date:
NAME
Cue Mahato Pty Ltd
Cue Mahakam Hilir Pty Ltd
Cue Kalimantan Pte Ltd*
Cue (Ashmore Cartier) Pty Ltd
Cue Sampang Pty Ltd
Cue Taranaki Pty Ltd
Cue Exploration Pty Ltd
Cue Palm Valley Pty Ltd**
Cue Mereenie Pty Ltd**
Cue Dingo Pty Ltd**
PRINCIPAL PLACE OF BUSINESS /
COUNTRY OF INCORPORATION
OWNERSHIP INTEREST
2022
2021
Australia
Australia
Singapore
Australia
Australia
Australia
Australia
Australia
Australia
Australia
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
All companies in the Group have a 30 June reporting date.
Shares held by Cue Mahakam Hilir Pty Ltd.
*
** Entities established by Cue Energy Resources Ltd, registered on 21 May 2021.
72
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 32.
INTERESTS IN JOINT OPERATIONS
PROPERTY
OPERATOR
Petroleum exploration properties
Carnarvon Basin - Western Australia
WA-359-P
WA-389-P
WA-409-P
Amadeus Basin
BP Developments Australia Pty Ltd
Cue Exploration Pty Ltd
BP Developments Australia Pty Ltd
Mereenie (OL4 and OL5 Production Licences) Central Petroleum
Palm Valley (OL3 Production Licence)
Central Petroleum
Dingo (L7 Production Licence)
Central Petroleum
Indonesia
CUE INTEREST %
2022
2021
PERMIT
EXPIRY
DATE
-
100*
-
7.5%**
15%**
15%**
21.5
25/04/2021
100
08/04/2021
20
12/10/2022
-
-
-
17/11/2023
05/11/2024
06/07/2039
Mahakam Hilir PSC
Cue Kalimantan Pte Ltd
100*
100*
15/04/2021
Petroleum development and production properties
New Zealand
PMP38160
Indonesia
Sampang PSC
Mahato PSC
OMV New Zealand Limited
5
5
02/12/2027
Medco Energi Sampang Pty Ltd
15
(8.18 Jeruk Field)
15
(8.18 Jeruk Field)
04/12/2027
Texcal Mahato EP Ltd
12.5
12.5
20/07/2042
*
WA-389-P and Mahakam Hilir PSC exploration permits have expired and regulatory processes for surrender are ongoing as at 30 June 2022. On 4 July 2022, surrender
processes for WA-389-P were completed.
** Completion of the acquisition of the Amadeus Basin Permits occurred on 1 October 2021.
Accounting policy for joint operations
A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to
the assets, and obligations for the liabilities, relating to the arrangement. The consolidated entity has recognised its
share of jointly held assets, liabilities, revenues and expenses of joint operations. These have been incorporated in the
financial statements under the appropriate classifications.
73
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 33.
BUSINESS COMBINATIONS
On 1 October 2021, the Company, in conjunction with NZOG, the Company’s majority shareholder, completed the
acquisition of the Amadeus Basin business including the Mereenie, Palm Valley and Dingo gas and oil fields in the
Northern Territory, Australia, from Central Petroleum Limited (ASX: CTP) (Central).
The Consolidated Entity’s acquired interests in the joint operation are a:
»
»
»
7.5% interest in the Mereenie gas and oil field (OL4 and OL5 Production Licences);
15% interest in the Palm Valley gas field (OL3 Production Licence); and
15% interest in the Dingo gas field (L7 Production Licence).
The ownership interests in the Amadeus Basin joint operation are as follows:
OWNERSHIP INTEREST
IN AMADEUS BASIN BUSINES
Mereenie
Palm Valley
Dingo
%
CUE ENERGY
RESOURCES
LIMITED
NZOG
CENTRAL
PETROLEUM
LIMITED
MACQUARIE
MEREENIE PTY
LTD
7.5%
15%
15%
17.5%
35%
35%
25%
50%
50%
50%
-
-
The drilling of 2 new production wells and 4 well recompletions in the Mereenie field and the Palm Valley 12
exploration well during the period were included in the carried cost contribution by the Group.
All three fields are in production and supply gas into the Eastern Australia and local Northern Territory gas markets.
The Consolidated Entity acquired the aforementioned interests for total consideration of $18.8 million, being the
contractually agreed price of $20.7 million less $1.9 million in respect of agreed adjustments, refer to note 14 to
the financial statements for further details. The total consideration comprised of an initial payment of $9.6 million to
Central and deferred consideration, the provisional fair value of which was measured at $9.2 million at 1 October 2021.
Subsequent to acquisition and prior to 30 June 2022, $2.9 million of the deferred consideration on acquisition was
settled, the remaining $6.3 million balance at 30 June 2022, all being classified as a current liability.
74
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 33.
BUSINESS COMBINATIONS (CONTINUED)
Details of the Consolidated Entity’s interest in the provisional fair value of the assets and liabilities upon acquisition are
as follows:
Cash and cash equivalents
Trade receivables
Oil and gas production properties
Inventories
Prepayments
Right-of-use assets
Deferred tax asset
Trade payables
Contract liabilities
Restoration provision
Lease liability
Deferred tax liability
Acquisition-date provisional fair value of the net assets acquired
Representing:
Contractually agreed price
Net revenue received
Working capital adjustment
Acquisition date provisional fair value of consideration paid and payable
Acquisition costs expensed to profit or loss
Cash used to acquire business, net of cash acquired:
Acquisition-date provisional fair value of total consideration paid/payable
Less: deferred consideration
Net cash used
PROVISIONAL
FAIR VALUE
$’000
62
4
33,609
331
54
50
1,964
(1,122)
(7,562)
(6,546)
(50)
(1,964)
18,830
20,700
(1,708)
(162)
18,830
1,576
18,830
(9,246)
9,584
As part of the acquisition, the Consolidated Entity assumed an obligation to supply gas to a customer from which
Central had received income prior to the Consolidated Entity acquiring its interest in the Amadeus Basin business. The
provisional fair value of this obligation upon acquisition is $4.16 million.
As detailed in note 29, the Group has entered into certain commitments for further exploration and development works
in respect of the Amadeus Basin assets acquired. The obligations reflected therein represent the Group’s proportion of
the total cost of works committed to at 30 June 2022.
i. Goodwill and cash generating units
Based on the provisional fair value assessment, no goodwill was recognised on the acquisition of the
Amadeus Basin business.
The Consolidated Entity operates as three operating segments, being the Australia, New Zealand and Indonesian
geographic segments. The Amadeus Basin business is comprised of two cash generating units being the Dingo and
Mereenie, including Palm Valley, fields within the Australian segment.
75
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 33.
BUSINESS COMBINATIONS (CONTINUED)
ii. Deferred consideration
The acquisition of the Amadeus Basin business included a deferred consideration element based on the Consolidated
Entity’s obligation to fund Central’s share of exploration, appraisal and development costs to a maximum of $12
million. During the period completion of 2 new production wells and 4 well recompletions in the Mereenie field and
drilling of the PV-12 well in the Palm Valley field were included in the deferred consideration.
The total consideration comprised of an initial payment of $9.6 million to Central and deferred consideration, the
provisional fair value of which was measured at $9.2 million at 1 October 2021. Subsequent to acquisition and prior to
30 June 2022, $2.9 million of deferred consideration was settled, the remaining $6.3 million balance at 30 June 2022
being a current liability.
iii. Contribution to the Consolidated Entity’s results
The Amadeus Basin assets contributed revenues of $8.21 million and net loss before tax of $0.08 million to the
Consolidated Entity from the date of the acquisition to 30 June 2022. The Amadeus Basin assets do not receive
any allocations of acquisition costs, corporate overhead, listing or finance costs, all of which are absorbed by the
Consolidated Entity’s core operations.
It is estimated that had the Amadeus Basin assets been acquired at the beginning of the reporting period, it would
have contributed estimated proforma revenues of $13.33 million and net profit before tax of $2.03 million for the period
from 1 July 2021 to 30 June 2022, past earnings not necessarily being a reflection of future earning capacity.
Accounting policy for business combinations
The acquisition method of accounting is used to account for business combinations regardless of whether equity
instruments or other assets are acquired.
The consideration transferred is the sum of the acquisition-date fair values of the assets transferred, equity
instruments issued or liabilities incurred by the acquirer to former owners of the acquiree and the amount of any
non-controlling interest in the acquiree. For each business combination, the non-controlling interest in the acquiree is
measured at either fair value or at the proportionate share of the acquiree’s identifiable net assets. All acquisition costs
are expensed as incurred to profit or loss.
On the acquisition of a business, the consolidated entity assesses the financial assets acquired and liabilities assumed
for appropriate classification and designation in accordance with the contractual terms, economic conditions, the
consolidated entity’s operating or accounting policies and other pertinent conditions in existence at the acquisition-date.
Where the business combination is achieved in stages, the consolidated entity remeasures its previously held equity
interest in the acquiree at the acquisition-date fair value and the difference between the fair value and the previous
carrying amount is recognised in profit or loss.
Contingent and deferred consideration to be transferred by the acquirer is recognised at the acquisition-date fair
value. Subsequent changes in the fair value of the contingent and deferred consideration classified as an asset or
liability is recognised in profit or loss. Contingent and deferred consideration classified as equity is not remeasured
and its subsequent settlement is accounted for within equity.
The difference between the acquisition-date fair value of assets acquired, liabilities assumed and any non-controlling
interest in the acquiree and the fair value of the consideration transferred and the fair value of any pre-existing
investment in the acquiree is recognised as goodwill. If the consideration transferred and the pre-existing fair value is
less than the fair value of the identifiable net assets acquired, being a bargain purchase to the acquirer, the difference
is recognised as a gain directly in profit or loss by the acquirer on the acquisition-date, but only after a reassessment
of the identification and measurement of the net assets acquired, the non-controlling interest in the acquiree, if any,
the consideration transferred and the acquirer’s previously held equity interest in the acquirer.
Business combinations are initially accounted for on a provisional basis. The acquirer retrospectively adjusts the
provisional amounts recognised and also recognises additional assets or liabilities during the measurement period,
based on new information obtained about the facts and circumstances that existed at the acquisition-date. The
measurement period ends on either the earlier of (i) 12 months from the date of the acquisition or (ii) when the acquirer
receives all the information possible to determine fair value.
76
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 34.
EVENTS AFTER THE REPORTING PERIOD
In July 2022, the Operator, Central Petroleum, and its Palm Valley and Dingo Joint Venture partners NZOG and the
Consolidated Entity, announced that the drilling program at Palm Valley and Dingo would be revised to defer the Dingo
well and evaluate the lower P2/P3 unit of the Pacoota Sandstone formation (P2/P3) instead of the Deep exploration
target at Palm Valley to prioritise near term production into a very strong East Coast gas market.
On 22 August 2022, the Palm Valley Joint Venture announced the decision to curtail further drilling in the lower P2
and P3 side track. This was due to the combination of the presence of formation water and no significant gas shows.
Total exploration costs of $2.2 million have been incurred in respect of this section of the well. In accordance with
the Group’s accounting policy $1.0 million were expensed in the year ended 30 June 2022, the remainder will be
expensed in the 2023 financial year.
No other matter or circumstance has arisen since 30 June 2022 that has significantly affected, or may significantly
affect the consolidated entity’s operations, the results of those operations, or the consolidated entity’s state of affairs
in future financial years.
NOTE 35.
RECONCILIATION OF PROFIT/(LOSS) AFTER INCOME TAX
TO NET CASH FROM/(USED IN) OPERATING ACTIVITIES
Profit/(loss) after income tax expense for the year
Adjustments for:
Share-based payments
Finance costs associated with abandonment provision
Depreciation
Amortisation
Net gain on foreign currency conversion
Change in operating assets and liabilities:
Increase in trade and other receivables
Decrease/(increase) in inventories
Decrease/(increase) in deferred tax assets
Increase in trade and other payables
Decrease in contract liabilities
(Decrease)/Increase in tax liabilities
Increase/(decrease) in deferred tax liabilities
Increase/(decrease) in provisions
Net cash from/(used in) operating activities
NOTE 36.
EARNINGS PER SHARE
CONSOLIDATED
2022
$’000
2021
$’000
16,068
(12,743)
188
259
82
5,415
520
(1,338)
(468)
(2,283)
570
(810)
551
(1,052)
(40)
17,662
179
(67)
76
2,804
3,599
(2,627)
21
247
916
-
(172)
959
(1,222)
(8,030)
CONSOLIDATED
2022
$’000
2021
$’000
Profit/(loss) after income tax attributable to the owners of Cue Energy Resources Limited
16,068
(12,743)
Weighted average number of ordinary shares used in calculating basic earnings per share
698,119,720
698,119,720
Weighted average number of ordinary shares used in calculating diluted earnings per share
698,119,720
698,119,720
NUMBER
NUMBER
77
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 36.
EARNINGS PER SHARE (CONTINUED)
Basic earnings/(loss) per share
Diluted earnings/(loss) per share
Accounting policy for earnings per share
Basic earnings per share
CENTS
CENTS
2.30
2.30
(1.83)
(1.83)
Basic earnings per share is calculated by dividing the earnings attributable to the owners of Cue Energy Resources
Limited, excluding any costs of servicing equity other than ordinary shares, by the weighted average number of
ordinary shares outstanding during the financial year, adjusted for bonus elements in ordinary shares issued during the
financial year.
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 shares assumed to have been issued for no consideration in relation to
dilutive potential ordinary shares.
NOTE 37.
SHARE-BASED PAYMENTS
On 23 July 2021, the Company issued 4,599,003 unlisted options to eligible employee under the share option scheme.
The options are exercisable at $0.078 (7.8 cents) per option and will vest on 23 July 2024 and expire on 22 July 2026.
The options were valued using Black-Scholes option pricing model. $72,376 of share-based payment expense was
recorded in relation to these options for the financial year ending 30 June 2022.
Set out below are summaries of options granted under the plan:
GRANT DATE
EXPIRY DATE
29/07/2017
01/07/2023
04/10/2019
01/07/2024
16/07/2020
01/07/2025
23/07/2021
22/07/2026
2022
EXERCISE
PRICE
BALANCE AT
THE START
OF THE YEAR
GRANTED
EXERCISED
$0.070
$0.090
$0.117
$0.078
3,784,025
3,853,298
3,743,260
-
-
-
-
4,599,003
11,380,583
4,599,003
EXPIRED/
FORFEITED/
OTHER
BALANCE AT
THE END OF
THE YEAR
-
-
-
-
-
(270,595)
(283,533)
(502,193)
(551,037)
3,513,430
3,569,765
3,241,067
4,047,966
(1,607,358)
14,372,228
Weighted average exercise price
$0.092
$0.078
$0.000
$0.091
$0.088
78
NOTES TO THE FINANCIAL STATEMENTS
30 JUNE 2022
NOTE 37.
SHARE-BASED PAYMENTS (CONTINUED)
The weighted average remaining contractual life of outstanding options at 30 June 2022 is 2.57 years
(30 June 2021: 2.52 years).
GRANT DATE
EXPIRY DATE
2021
EXERCISE
PRICE
BALANCE AT
THE START
OF THE YEAR
GRANTED
EXERCISED
EXPIRED/
FORFEITED/
OTHER
BALANCE AT
THE END OF
THE YEAR
29/07/2019
01/07/2023
$0.070
04/10/2019
01/07/2024
$0.090
3,784,025
3,853,298
-
-
16/07/2020
01/07/2025
$0.117
-
3,743,260
7,637,323
3,743,260
-
-
-
-
-
-
-
-
3,784,025
3,853,298
3,743,260
11,380,583
Weighted average exercise price
$0.080
$0.117
$0.000
$0.000
$0.092
For the options granted during the current financial year, the valuation model inputs used to determine the fair value at
the grant date, are as follows:
GRANT DATE
EXPIRY DATE
SHARE PRICE
AT GRANT
DATE
EXERCISE
PRICE
EXPECTED
VOLATILITY
DIVIDEND
YIELD
RISK-FREE
INTEREST
RATE
FAIR VALUE
AT GRANT
DATE
23/07/2021
22/07/2026
$0.070
$0.078
59.00%
-
0.58%
$0.033
Accounting policy for share-based payments
Equity-settled share-based compensation benefits are provided to employees.
Equity-settled transactions are awards of shares, or options over shares, that are provided to employees in exchange
for the rendering of services. Cash-settled transactions are awards of cash for the exchange of services, where the
amount of cash is determined by reference to the share price.
The cost of equity-settled transactions are measured at fair value on grant date. Fair value is independently
determined using either the Binomial or Black-Scholes option pricing model that takes into account the exercise
price, the term of the option, the impact of dilution, the share price at grant date and expected price volatility of the
underlying share, the expected dividend yield and the risk free interest rate for the term of the option, together with
non-vesting conditions that do not determine whether the consolidated entity receives the services that entitle the
employees to receive payment. No account is taken of any other vesting conditions.
The cost of equity-settled transactions are recognised as an expense with a corresponding increase in equity over the
vesting period. The cumulative charge to profit or loss is calculated based on the grant date fair value of the award,
the best estimate of the number of awards that are likely to vest and the expired portion of the vesting period. The
amount recognised in profit or loss for the period is the cumulative amount calculated at each reporting date less
amounts already recognised in previous periods.
If equity-settled awards are modified, as a minimum an expense is recognised as if the modification has not been
made. An additional expense is recognised, over the remaining vesting period, for any modification that increases the
total fair value of the share-based compensation benefit as at the date of modification.
If the non-vesting condition is within the control of the consolidated entity or employee, the failure to satisfy the
condition is treated as a cancellation. If the condition is not within the control of the consolidated entity or employee
and is not satisfied during the vesting period, any remaining expense for the award is recognised over the remaining
vesting period, unless the award is forfeited.
If equity-settled awards are cancelled, it is treated as if it has vested on the date of cancellation, and any remaining
expense is recognised immediately. If a new replacement award is substituted for the cancelled award, the cancelled
and new award is treated as if they were a modification.
79
DIRECTORS’ DECLARATION
30 JUNE 2022
In the directors’ opinion:
»
»
»
»
the attached financial statements and notes comply with
the Corporations Act 2001, the Australian Accounting
Standards, the Corporations Regulations 2001 and other
mandatory professional reporting requirements;
the attached financial statements and notes comply with
International Financial Reporting Standards as issued
by the International Accounting Standards Board as
described in note 2 to the financial statements;
the attached financial statements and notes give a
true and fair view of the consolidated entity’s financial
position as at 30 June 2022 and of its performance for
the financial year ended on that date; and
there are reasonable grounds to believe that the
company will be able to pay its debts as and when they
become due and payable.
The directors have been given the declarations required by
section 295A of the Corporations Act 2001.
Signed in accordance with a resolution of directors made
pursuant to section 295(5)(a) of the Corporations Act 2001.
On behalf of the directors
Alastair McGregor
Non-Executive Chairman
25 August 2022
80
80
INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS
OF CUE ENERGY RESOURCES LIMITED
Independent Auditor’s Report
To the shareholders of Cue Energy Resources Limited
Report on the audit of the Financial Report
Opinion
We have audited the Financial Report of
Cue Energy Resources Limited
(the
Company).
In our opinion, the accompanying Financial
Report of the Company is in accordance with
the Corporations Act 2001, including:
•
•
giving a true and fair view of the Group’s
financial position as at 30 June 2022 and
of its financial performance for the year
ended on that date; and
complying with Australian Accounting
Standards
the Corporations
and
Regulations 2001.
Basis for opinion
The Financial Report comprises:
• Consolidated Statement of financial position as at
30 June 2022;
• 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 then ended;
• Notes
including a summary of significant
accounting policies;
• Directors’ Declaration.
The Group consists of the Company and the entities it
controlled at the year end or from time to time during
the financial year.
We conducted our audit in accordance with Australian Auditing Standards. We believe that the audit
evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
Our responsibilities under those standards are further described in the Auditor’s responsibilities for the
audit of the Financial Report section of our report.
We are independent of the Group in accordance with the Corporations Act 2001 and the ethical
requirements of the Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics
for Professional Accountants (including Independence Standards) (the Code) that are relevant to our
audit of the Financial Report in Australia. We have fulfilled our other ethical responsibilities in
accordance with these requirements.
KPMG, an Australian partnership and a member firm of the KPMG global organisation of independent member firms affiliated
with KPMG International Limited, a private English company limited by guarantee. All rights reserved. The KPMG name and
logo are trademarks used under license by the independent member firms of the KPMG global organisation. Liability limited by
a scheme approved under Professional Standards Legislation.
81
INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS
OF CUE ENERGY RESOURCES LIMITED
Key Audit Matters
The Key Audit Matters we identified are:
• Acquisition of interest in the Amadeus
Basin Assets; and
• Restoration provision relating to the
Maari field.
Key Audit Matters are those matters that, in our
professional judgement, were of most significance in
our audit of the Financial Report of the current period.
These matters were addressed in the context of our
audit of the Financial Report as a whole, and in forming
our opinion thereon, and we do not provide a separate
opinion on these matters.
Acquisition of Interest in Amadeus Basin Assets of $18.8 million
Refer to Note 33 Business combinations
The key audit matter
How the matter was addressed in our audit
On 1 October 2021, the Group completed the
acquisition of interests as a joint venture
partner in the Mereenie, Palm Valley and Dingo
gas and oil fields in the Northern Territory,
Australia.
This Business combination is a key audit matter
due to:
• The financial significance of the transaction
to the Group; and
• the judgment required by the Group to
measure the fair values of assets acquired
and liabilities assumed, including:
-
-
-
-
oil and gas production properties;
prepaid gas and assumed obligations to
supply gas to customers where
income has been received in advance;
restoration obligations; and
acquisition date deferred tax balances.
These factors and the complexity of the
acquisition accounting required significant audit
effort and involvement of senior audit team
members, including our specialists, in
assessing this key audit matter.
Our procedures included:
•
•
•
•
read the acquisition agreements and other
related transaction documents to understand
the structure, key terms and conditions;
evaluated the acquisition accounting
methodology applied by the Group against the
requirements of the accounting standards;
assessed the Group’s determination of the
accounting acquisition date and fair value of
purchase consideration with reference to the
underlying asset sale agreement and
accounting standard requirements;
evaluated the qualifications, competence and
objectivity of external and internal experts
used by the Group including an assessment as
to the extent to which the information
provided by them could be relied upon;
• with the assistance of our valuation
specialists, evaluated the Group’s assessment
of the fair value of oil and gas production
properties;
•
assessed the significant judgements
impacting the fair value of net assets acquired
including:
-
assessing the valuation methodology
applied was in accordance with the
requirements of Australian Accounting
Standards;
82
INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS
OF CUE ENERGY RESOURCES LIMITED
-
-
challenged the feasibility of forecast
cashflows, reserve and resource
estimates, production profiles and useful
life; comparing for consistency with other
internal and external information including
reports prepared by management’s
experts and post acquisition cash flows;
and
challenged the Group’s assumptions for
oil and gas prices, inflation rates, and
discount rate by comparing to available
external information including observable
market prices, publicly available industry
guidance and information from
comparable companies.
• with the assistance of our tax specialists,
assessed the appropriateness of the
recognised deferred tax balances against
accounting standard requirements;
•
•
assessed the identification and measurement
of prepaid gas and assumed obligations to
supply gas to customers where income has
been received in advance, with reference to
contractual obligations, and against accounting
standard requirements; and
assessed the appropriateness of the Group’s
disclosures in the financial report using our
understanding obtained from our testing and
against the requirements of accounting
standards.
83
INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS
OF CUE ENERGY RESOURCES LIMITED
Restoration provision relating to the Maari field included within provisions of $12.8 million
Refer to Note 21 Provisions
The key audit matter
How the matter was addressed in our audit
Our procedures included:
•
•
•
•
•
•
the
to determine
tested design of key controls in the Group’s
process
restoration
provision. This included the determination,
review and approval by the Group of key
inputs included in the calculation such as life
of asset reserves and production profiles,
discount rates, future restoration costs, and
timing of future cash flows;
assessed the nature and extent of the work
performed by the Group’s external expert in
identifying future restoration activities and
assessing the timing and likely cost of such
activities. We compared the nature and
extent of restoration work to the relevant
regulatory
inspected
requirements, and
relevant correspondence from government
and regulatory bodies. We compared the
timing of restoration activities to the Group’s
reserves and resources estimates, expected
production profile and useful life;
used our knowledge of the Group and our
industry experience, and considering other
publicly available information from the joint
operation partners, assessed the feasibility of
the future restoration costs and their timing;
evaluated
objectivity of the Group’s
external experts;
the scope, competency and
internal and
evaluated the discount and inflation rates
applied to the Group’s net present value of
the restoration provision against publicly
available data, including risk free rates; and
assessed the
integrity of the provision
calculation including the accuracy of the
underlying calculation formulas.
We identified the restoration provision for the
Maari field as a key audit matter due to:
•
•
relating
the estimation uncertainty
to
forecast restoration cash flows for the
auditor
Maari
their
judgement
appropriateness; and
require
evaluate
asset which
to
the significant size of the restoration
provision relative to the Group’s financial
position.
The Group incurs obligations to close, restore
and rehabilitate its sites and associated facilities.
We focused on the following key estimates
made by the Group in determining its restoration
provision for Maari:
•
•
•
•
useful life of assets including the economic
reserves and production profiles;
the interpretation of legislative regulatory
requirements governing
the Group’s
obligations;
the cost and timing of future rehabilitation
costs; and
discount and inflation rates applied to the
Group’s net present value of forecast cash
flows used to determine the restoration
provision.
84
INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS
OF CUE ENERGY RESOURCES LIMITED
Other Information
Other Information is financial and non-financial information in Cue Energy Resources Limited’s annual
reporting which is provided in addition to the Financial Report and the Auditor’s Report. The Directors
are responsible for the Other Information.
The Other Information we obtained prior to the date of this Auditor’s Report were the Directors’ Report,
Operations and Financial Review, and the Shareholder Information. The Chairman’s Overview,
Reserves and Resources Summary and Sustainability are expected to be made available to us after the
date of the Auditor's Report.
Our opinion on the Financial Report does not cover the Other Information and, accordingly, we do not
and will not express an audit opinion or any form of assurance conclusion thereon, with the exception
of the Remuneration Report and our related assurance opinion.
In connection with our audit of the Financial Report, our responsibility is to read the Other Information.
In doing so, we consider whether the Other Information is materially inconsistent with the Financial
Report or our knowledge obtained in the audit, or otherwise appears to be materially misstated.
We are required to report if we conclude that there is a material misstatement of this Other Information,
and based on the work we have performed on the Other Information that we obtained prior to the date
of this Auditor’s Report we have nothing to report.
Responsibilities of the Directors for the Financial Report
The Directors are responsible for:
• preparing the Financial Report that gives a true and fair view in accordance with Australian
Accounting Standards and the Corporations Act 2001;
•
•
implementing necessary internal control to enable the preparation of a Financial Report that
gives a true and fair view and is free from material misstatement, whether due to fraud or error;
and
assessing the Group and Company’s ability to continue as a going concern and whether the use
of the going concern basis of accounting is appropriate. This includes disclosing, as applicable,
matters related to going concern and using the going concern basis of accounting unless they
either intend to liquidate the Group and Company or to cease operations, or have no realistic
alternative but to do so.
Auditor’s responsibilities for the audit of the Financial Report
Our objective is:
•
•
to obtain reasonable assurance about whether the Financial Report as a whole is free from
material misstatement, whether due to fraud or error; and
to issue an Auditor’s Report that includes our opinion.
Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in
accordance with Australian Auditing Standards will always detect a material misstatement when it
exists.
Misstatements can arise from fraud or error. They are considered material if, individually or in the
aggregate, they could reasonably be expected to influence the economic decisions of users taken on
the basis of the Financial Report.
85
INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS
OF CUE ENERGY RESOURCES LIMITED
A further description of our responsibilities for the audit of the Financial Report is located at the Auditing
and
at:
https://www.auasb.gov.au/admin/file/content102/c3/ar1_2020.pdf. This description forms part of our
Auditor’s Report.
Assurance
Standards
website
Board
Report on the Remuneration Report
Opinion
Directors’ responsibilities
In our opinion, the Remuneration Report of
Cue Energy Resources Limited for the year
ended 30 June 2022, complies with Section
300A of the Corporations Act 2001.
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 responsibilities
We have audited the Remuneration Report included
in pages 13 to 18 of the Directors’ report for the
year ended 30 June 2022.
Our responsibility is to express an opinion on the
Remuneration Report, based on our audit conducted in
accordance with Australian Auditing Standards.
KPMG
Vicky Carlson
Partner
Melbourne
25 August 2022
86
ADDITIONAL SHAREHOLDER INFORMATION
1. DISTRIBUTION OF EQUITABLE SECURITIES
The shareholder information set out below was applicable as at 1 September 2022:
1 to 1,000
1,001 to 5,000
5,001 to 10,000
10,001 to 100,000
100,001 and over
Holding less than a marketable parcel
ORDINARY SHARES
OPTIONS OVER
ORDINARY SHARES
NUMBER OF
HOLDERS
% OF TOTAL
SHARES
NUMBER OF
HOLDERS
% OF TOTAL
SHARES
ISSUED
71
173
526
1,521
310
2,601
355
0.00
0.08
0.66
7.40
91.86
100
-
-
-
-
-
8
8
-
-
-
-
-
100
100
-
2. REGISTERED TOP 20 SHAREHOLDERS
The registered names and holdings of the 20 largest holdings of quoted ordinary shares in the Company
as at 1 September 2022:
SHAREHOLDER
1.
2.
3.
4.
5.
6.
7.
8.
9.
NZOG OFFSHORE LIMITED
BNP PARIBAS NOMS PTY LTD
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