29 October 2024
QUARTERLY ACTIVITIES
REPORT
For the quarter ended 30
September 2024
88 Energy Limited (ASX:88E, AIM:88E,
OTC:EEENF) (88 Energy, 88E
or the Company) provides
the following report for the quarter ended 30 September
2024.
Highlights
Project Phoenix (~75% WI)
· Significant Resources
Update: New Contingent Resources
estimates at Project Phoenix for the SMD-B and SFS reservoirs,
independently verified by ERCE Australia Pty Ltd (ERCE) during the quarter. Existing
Gross Best Estimate (2C)
Contingent Resources increased over 50%, with an additional gross
128 million barrels of oil equivalent (MMBOE), 81MMBOE Net
Entitlement to 88E, added from the Shelf Margin Delta (SMD-B) and Slope Fan System
(SFS) reservoirs,
comprising1:
Ø 115
million barrels (MMbbl) of Gross recoverable hydrocarbon liquids
(oil and natural-gas liquids), 73 MMbbl Net Entitlement to 88
Energy1;
and
Ø 68 billion
cubic feet (BCF) of Gross recoverable gas, 43 BCF Net Entitlement
to 88 Energy1
· Strategic Development
Opportunity Confirmed: Featuring the
critical characteristics required for future commercialisation and
monetisation, including:
Ø A
combined Best Estimate
(2C) Contingent Resources
of Gross 251 MMbbl (159 MMbbl Net
to 88E) of oil and natural-gas liquids (NGLs) across four
stacked reservoirs, accessible from single surface
location1;
Ø Premium
37- 40o API gravity oil successfully recovered from Hickory-1, for a
highly marketable and valuable light oil
product1; and
Ø Located on
prime Alaskan State lands, directly adjacent to the Trans-Alaskan
Pipeline System (TAPS), and the Dalton Highway, with close
proximity to Deadhorse (oil and gas services hub);
· Successful outcomes from Hickory-1 delivered a platform for
monetisation of Project Phoenix, justifying further advancement.
Near-term advancement
activities are focused on:
Ø Initiating
a formal farm-out process to attract a strategic partner for future
drilling and development of Project Phoenix;
Ø Planning
and design for a potential horizontal flow test and early stage
production system;
Ø 3rd party review by ResFrac of the Hickory-1
stimulation and flow design, modelling production potential and
optimising the completion strategy for a potential horizontal well;
and
Ø Constructive Partner Progress: Ongoing discussions with joint
venture partner Burgundy Xploration, LLC (Burgundy), could result in Burgundy
carrying all or part of 88 Energy's share of the 2025/2026 work
program in exchange for an additional working interest in the
Project.
1. Refer announcement released to ASX
on 18 September 2024 for full details.
88E
is not aware of any new information or data that materially affects
the information included in the relevant market announcement and
that all material assumptions and technical parameters underpinning
the estimates continue to apply and have not materially
changed.
Project Leonis (100% WI)
· Planning ongoing for the Tiri-1 exploration well, designed to
test the Tiri prospect in the USB formation;
· Additional deeper resource potential identified and being
assessed within the acreage, including mapping of potential new
resource, AVO studies.and resource estimation; and
· Ongoing farm-out process seeking a funding partner ahead of
potential Tiri-1 drilling in 2026.
Namibia PEL 93 (20% WI)
· Data
processing for the ~200-line km 2D seismic program is ongoing, both
in the field and at Earth Signal Processing in Calgary, with final
interpretation expected in Q4 2024;
· Program outcomes set to include:
Ø Validation
of up to 10 independent structural closures;
Ø Delivery
of a maiden independently certified Prospective Resource estimate
expected in H1 2025; and
Ø Identification of future potential drilling locations
targeting the Damara play.
Project Longhorn (~65% WI)
· Production marginally increased from 391 BOE per day gross
(average Q2 2024, ~63% oil) to Q3 2024 average of 395 BOE per day
gross (~69% oil). Q3 production was expected to be higher at around
450-460 BOE per day gross but the operations experienced unplanned
downtime. This included gas plant downtime resulting in the need to
vent gas with higher backpressure and water station battery issues
following a lightning strike requiring certain wells to be shut-in
for specific periods during the quarter.
· In
June 2024, the Company received a cash flow distribution of
~A$0.7M, post final workover expenditure.
Corporate
·
Cash balance of A$5.5 million and all Hickory-1
flow test payments made and program closed;
·
Burgundy obliged to pay outstanding cash call of
~US$4 million in Q4 2024, which will further strengthen the balance
sheet;
· Budget
for the forward twelve-month activity schedule fully funded for
delivery, including Phoenix horizontal well pre-planning /
permitting and farmout activities, Leonis Tiri-1 planning and
farmout activites, PEL93 work program and Longhorn operations;
and
·
Lower Corporate costs for the 9 months in 2024 of
$2.7M compared to 9 months in 2023 of $4m (over a 30% reduction
YTD).
Project Phoenix (~75% WI)
Project Phoenix is an oil-bearing
conventional reservoir play identified during the drilling and
logging of Icewine-1 and Hickory-1 and adjacent to offset drilling
and testing. Project Phoenix is strategically located on the Dalton
Highway with the Trans-Alaskan Pipeline System bisecting the
acreage.
Hickory-1
Summary
The Hickory-1 discovery well was
drilled in February 2023 and flow tested during the Alaskan winter
season in 1H 2024. The testing operations focused on the two
shallower reservoirs, the Upper SFS (USFS) reservoir, previously untested,
and the SMD-B reservoir. Each zone was independently isolated,
stimulated, and flowed to the surface using nitrogen lift to
facilitate efficient well clean-up.
Quality and deliverability of both
reservoirs was demonstrated via oil to surface:
â–º
USFS produced at a peak
flow rate of over 70 bopd of light oil and produced under natural
flow, which differentiates the USFS from other adjacent offset
wells;
â–º
SMD produced at a peak
flow rate of ~50 bopd of light oil and little to no measurable gas
which presents a production rate with low gas to oil ratio;
and
â–º
Multiple oil samples recovered measured oil
gravities between 37 to 40 API (representing a valuable and
marketable light crude oil).
For full details of the USFS and SMD
test results please refer to the ASX announcements dated 2 April
2024 for USFS and 15 April 2024 for SMD-B.
Figure 1: Project Phoenix multi-reservoir discoveries with
significant light oil resource confirmed.
Significant
Contingent Resource Update for Project Phoenix
Major Milestone
Achieved: New Contingent Resources
estimates at Project Phoenix for the SMD-B and SFS reservoirs,
independently verified by ERCE Australia Pty Ltd
(ERCE)
Significant Resources
Update: Existing Project Phoenix
Gross Best Estimate (2C) Contingent Resources
increases by over 50%, with an additional
gross 128 million barrels of oil equivalent (MMBOE)1, 81
MMBOE Net Entitlement to 88E1, added from the SMD-B and
SFS reservoirs, comprising:
â–º
115 million barrels (MMbbl) of Gross recoverable
hydrocarbon liquids (oil and natural-gas liquids), 73 MMbbl Net
Entitlement to 88 Energy; and
â–º
68 billion cubic feet (BCF) of Gross recoverable gas, 43 BCF
Net Entitlement to 88 Energy
Multi-Reservoir
Discovery: Estimates from ERCE (SMD-B and
SFS reservoirs) and Netherland, Sewell & Associates, Inc
(NSAI) Basin Floor
Fan (BFF) reservoir
confirm Project Phoenix as a robust multi-reservoir discovery, with
a total combined Gross Best Estimate 2C
Contingent Resource of approximately 378 MMBOE (239 MMBOE Net Entitlement to 88E)1
Material Upside
Potential: Prospective Resources of Net Mean
Unrisked 155 MMbbl1,2 independently verified by Lee
Keeling and Associates Inc, in the Kuparuk (undrilled), SMD-A and C
reservoirs (oil interpreted on logs at Hickory-1), offer compelling
additional upside potential. Unrisked net 3U (high) of 321 MMbbls,
2U (best) of 153 MMbbls, 1U (low) of 53 MMbbls1,2. The
geological Chance of Success (CoS) of these prospects has been
estimated as 71%, 81% and 81% respectively.
Figure 2: Project Phoenix
confirmed 88 Energy Net Entitlement Resources summary showing
untested potential upside. This information should be read in
conjunction with Tables 1 to 7 and the cautionary statement in the
ASX announcement dated 18 September 2024, which contains further
information relating to the contingent and prospective resource
estimates.
1. Refer announcement released to ASX on 18 September 2024 for
full details
2. Cautionary Statement in
relation to Prospective Resources: The estimated quantities of petroleum that may be potentially
recovered by the application of a future development project relate
to undiscovered accumulations. These estimates have both an
associated risk of discovery and a risk of development. Further
exploration, appraisal and evaluation are required to determine the
existence of a significant quantity of potentially recoverable
hydrocarbons. 88E is not aware of any new information or data that
materially affects the information included in the relevant market
announcement and that all material assumptions and technical
parameters underpinning the estimates continue to apply and have
not materially changed.
Advancement
Activities and Key Milestones
The Project Phoenix joint venture
(JV) is currently
planning a flow test of the SMD reservoir over an extended period
at the Franklin Bluffs gravel pad in CY 2025/26. The reuse of the
Franklin Bluffs gravel pad (previously used to drill the Icewine-1
and 2 wells) offers considerable cost savings over a purpose-built
ice pad without compromising the objectives. The design phase for
the horizontal well is progressing with ongoing assessments by
ResFrac to optimise the completion strategy.
Joint Venture potential
transaction
In parallel, 88 Energy is in
advanced discussions with its JV partner Burgundy Xploration, LLC
(Burgundy)
regarding a potential transaction after Burgundy completed an
extensive review (internal and external) of Project Phoenix data.
The potential transaction involves Burgundy providing a carry to
88E across an anticipated 2025/26 work program including the
drilling, completion and extended flow testing of a horizontal well
at the Franklin-Bluffs gravel pad adjacent to the Dalton Highway,
in return for additional working interest in Project
Phoenix:
â–º
Any carry is subject to Burgundy raising the
capital required through a near-term public listing
â–º
Burgundy to pay US$0.35M by 31 October 2024 in
return for the Company extending the December 2023 standstill
agreement for outstanding Flow Test AFE costs of ~US$3M until 31
December 2024, to allow Burgundy time to complete its intended
public listing and raise capital towards the advancement of Project
Phoenix
â–º
Burgundy understands that under the current
standstill agreement, if payment of the flow test cash call is not
made by 31 December 2024, this will require Burgundy to transfer to
88E-Accumulate 50% of Burgundy's working interest in Project
Phoenix's Toolik River Unit leases.
â–º
The Company maintains its rights under the joint
operating agreement (JOA) should Burgundy not be able to pay any
future cash calls, including exercising the option to require
Burgundy to relinquish its working interests in Project Phoenix and
the Joint Venture.
There is no guarantee that any
transaction with Burgundy will be completed. Accordingly, the
Company intends to launch a formal farm-out process in Q4 2024 to
ensure progress continues, irrespective of the outcome of
Burgundy's listing process.
Project Phoenix key
milestones
|
|
|
|
|
|
|
Indicative Project Phoenix development
timeline1
|
H1-24
|
H2-24
|
H1-25
|
H2-25
|
H1-26
|
H2-26
|
Successful Hickory-1 flow test flows
light crude oil to surface
|
P
|
|
|
|
|
|
Post-well analysis and updated
Contingent Resource Estimate
|
|
P
|
|
|
|
|
Targeted farmout to de-risk and
provide pathway to production test
|
|
n
|
n
|
|
|
|
Farm-out program to secure funding
for forward program
|
|
n
|
n
|
n
|
|
|
Planning/permitting/design for
horizontal production test[1]
|
|
n
|
n
|
n
|
n
|
|
Extended horizontal production
test1
|
|
|
|
|
n
|
n
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
This timeline is indicative and subject to change. The Company
reserves the right to alter this timetable at any time. Horizontal
production test subject to farm-out/funding as well as government
and other approvals.
Project Leonis (100% WI)
The Company reported a maiden
Prospective Resource net mean estimate of 381 million barrels
(MMbbls) of
recoverable oil in the newly named Tiri Prospect (Upper Schrader
Bluff Formation/USB) for Project Leonis.
Unrisked
net 3U (high) of 671 MMbbls, 2U (best) of 338 MMbbls and 1U (low)
of 167 MMbbls1,2.
The initial Prospective Resource
estimate followed an extensive data suite review including 3D and
2D seismic data, well logs from Hemi Springs Unit-3, Hailstorm-1
and nearby wells adjacent to Project Leonis acreage, along with
extensive petrophysical analysis and mapping.
The USB formation is the same proven
producing zone as found in nearby Polaris, Orion and West Sak oil
fields to the north-west.
These proven USB producers served as
important calibration points for the Leonis petrophysical model.
The Leonis USB prospect has been fully delineated and mapped
following a review of reprocessed 3D seismic data and a 3rd party
dedicated fault mapping study to assist in prospect
definition.
Project
Leonis: Forward Program
Continuing on from the successful
outcomes at Hickory-1, Fairweather, LLC has been engaged and is
progressing the planning for the newly named Tiri-1 exploration
well. The well will be designed to drill, log and test the Tiri
Prospect in the USB formation. The company intends to utilise the
existing gravel pad at the Hemi Springs Unit-3 well location, to
reduce costs.
Timing for drilling the Tiri-1 exploration well is
dependent on securing a successful farm-out partner.
Additional to the Tiri prospect in
the USB, 88 Energy has also identified, and is assessing, deeper
prospective zones within the acreage. The Company is currently
mapping the potential new resource and advancing AVO studies and
resource estimation. This work is expected to be completed in
Q4 2024 and will add to the extensive data set and resource
potential currently being marketed for farm-out.
1. Refer announcement released to ASX
on 4 June 2024 for further details
2. Cautionary Statement in relation to
Prospective Resources: The estimated quantities of petroleum
that may be potentially recovered by the application of a future
development project relate to undiscovered accumulations. These
estimates have both an associated risk of discovery and a risk of
development. Further exploration, appraisal and evaluation are
required to determine the existence of a significant quantity of
potentially recoverable hydrocarbons. 88E is not aware of any new
information or data that materially affects the information
included in the relevant market announcement and that all material
assumptions and technical parameters underpinning the estimates
continue to apply and have not materially
changed.
Namibia PEL 93 (20% WI)
Namibia has been identified as one
of the last remaining under-explored, onshore frontier basins and
one of the world's most prospective new exploration zones. PEL 93
is more than 10 times larger in surface area than 88 Energy's
Alaskan portfolio and more than 70 times larger than Project
Phoenix.
Historical assessment by JV operator
and majority working interest owner (55%) Monitor Exploration
Limited (Monitor)
utilised a combination of geological and geophysical techniques and
interpretation of the data produced by them to identify the Owambo
Basin. This validated the significant potential of the acreage
which was awarded as PEL 93 in 2018, identifying ten (10)
independent structural closures from airborne geophysical methods
and partly verifying these using existing 2D seismic
coverage.
In July 2024, Polaris Natural
Resources Development Ltd (Polaris) successfully acquired
203-line km of 2D seismic data with data processing ongoing, both
in-field and at Earth Signal Processing in Calgary with final
interpretation to be finalised in Q4 2024.
Results of the new 2D seismic
acquisition will be integrated with existing data to refine current
prospect interpretation. Expected program outcomes
include:
Ø Validation
of up to 10 independent structural closures;
Ø Delivery
of a maiden, independently certified, Prospective Resource estimate
expected in H1 2025; and
Ø Identification of future potential drilling locations
targeting the Damara play.
Recent drilling results on nearby
acreage have highlighted the potential of a new and underexplored
conventional oil and gas play in the Damara Fold belt, referred to
as the Damara Play.
Neighbouring leaseholder
Reconnaissance Energy Africa Ltd (Recon Africa) (TSXV: RECO) announced
the spud of its first well in July 2024. Naingopo-1 on Petroleum
Exploration Licence 73 (PEL73) in the Owambo Basin, which is
modelled to be a continuation of the interpreted opportunity at
PEL93. On 3 October 2024, Recon Africa announced that it will
penetrate its primary objective of the Damara Fold Belt play
imminently and reach total depth towards the end of
October.
In August 2024, growth-focused oil
and gas acquisition, development, and production company BW Energy
Limited (BW Energy) farmed
into Recon Africa's Namibian acreage. BW Energy acquired a 20%
working interest in PEL 73 with a US$16 million equity investment,
to participate in two Damara Fold Belt exploration wells and a 3D
seismic program and with an option to participate in two Rift Basin
exploration wells over a 2-year period.
This new investment demonstrates
strong industry and capital market support for the potential of the
Owambo Basin and the Damara Play.
Project Longhorn (~65% WI)
Production increased marginally from
391 BOE per day gross (Q2 2024 average, ~63% oil) to 395 BOE per
day gross (Q3 2024 average, ~69% oil). Q3 production was expected
to be higher at around 450-460 BOE per day gross but the operations
experienced unplanned downtime. This included gas plant downtime
resulting in the need to vent gas with higher backpressure and
water station battery issues following a lightning strike requiring
certain wells to be shut-in for specific periods during the
quarter.
In June 2024, the Company received a
cash flow distribution of ~A$0.7M, post final workover
expenditure.
Peregrine & Umiat (100% WI)
88 Energy was successful in securing
a suspension for Project Peregrine on 1 December 2023 for an
initial period of 12 months due to the proposed new regulations
governing the management of surface resources in the National
Petroleum Reserve-A (NPR-A). On 25 June 2024, the Company applied
for suspension of the Umiat Unit and leases on the same basis as
the Project Peregrine suspension, requesting an initial 1-year
suspension that will be reviewed as required. On 31 July 2024 The
Bureau of Land Management Alaska approved a 12-month suspension of
the Umiat Unit and leases from 1 July 2024 to 30 June
2025.
During the suspension period, 88
Energy will continue the refinement of internal geological and
geophysical models/interpretations. The suspension will relieve 88
Energy of the obligation to pay Umiat lease rentals due in Q4 2024
of ~A$0.1 million.
Finance
As at 30 September 2024, the
Company's cash balance was A$5.5M.
The ASX Appendix 5B attached to this
quarterly report contains the Company's cash flow statement for the
quarter. The material cash flows for the period were:
· Exploration and evaluation expenditure of A$2.04M (June 2024
quarter: A$17.3M) predominantly related to final payments for
Hickory-1, which have now been closed out.
· Administration, staff, and other costs of A$0.7M (June 2024
quarter: A$1.1M) which included fees paid to Directors and
consulting fees paid to Directors of A$0.18M. Lower salary costs
between quarters included additional management salary reductions
in Q3 and other corporate cost reductions
implemented.
· Burgundy obligated to pay outstanding cash call of ~US$4
million (flow test, G&A/G&G) in Q4 2024 which will further
strengthen the balance sheet. Burgundy paid US$0.15M in
Q3.
Information required by ASX Listing Rule
5.4.3
Project Name
|
Location
|
Net
Area (acres)
|
Interest at beginning of
Quarter
|
Interest at end of
Quarter
|
|
|
|
Phoenix
|
Onshore, North Slope
Alaska
|
44,562
|
~75%
|
~75%
|
Icewine West2
|
Onshore, North Slope
Alaska
|
-
|
~75%
|
~0%
|
Peregrine1
|
Onshore, North Slope Alaska
(NPR-A)
|
125,735
|
100%
|
100%
|
Longhorn
|
Onshore, Permian Basin
Texas
|
2,830
|
~65%
|
~65%
|
Leonis
|
Onshore, North Slope
Alaska
|
25,431
|
100%
|
100%
|
Umiat3
|
Onshore, North Slope Alaska
(NPR-A)
|
17,633
|
100%
|
100%
|
PEL 93
|
Onshore, Owambo Basin,
Namibia
|
914,270
|
20%
|
20%
|
1. Refer announcement released to ASX on 21
December 2023 regarding Project Peregrine 12-month suspension until
30 November 2024
2. Acreage that was deemed non-core to 88 Energy
was relinquished during the quarter, providing a reduction in lease
costs from a focused strategy that unlocks value from key acreage
positions with strategic locations, as announced to the ASX on 4
June 2024
3. Refer 2024 Half Yearly announcement released to
ASX on 2 September 2024, regarding Umiat 12-month suspension until
30 June 2025
Pursuant to the requirements of the
ASX Listing Rules Chapter 5 and the AIM Rules for Companies, the
technical information and resource reporting contained in this
announcement was prepared by, or under the supervision of, Dr
Stephen Staley, who is a Non-Executive Director of the Company. Dr
Staley has more than 40 years' experience in the petroleum
industry, is a Fellow of the Geological Society of London, and a
qualified Geologist / Geophysicist who has sufficient experience
that is relevant to the style and nature of the oil prospects under
consideration and to the activities discussed in this document. Dr
Staley has reviewed the information and supporting documentation
referred to in this announcement and considers the prospective
resource estimates to be fairly represented and consents to its
release in the form and context in which it appears. His academic
qualifications and industry memberships appear on the Company's
website, and both comply with the criteria for "Competence" under
clause 3.1 of the Valmin Code 2015. Terminology and standards
adopted by the Society of Petroleum Engineers "Petroleum Resources
Management System" have been applied in producing this
document.
This announcement has been authorised by the
Board.
Media and Investor Relations:
88
Energy Ltd
Ashley Gilbert, Managing
Director
|
|
Ashley Gilbert, Managing
Director
|
|
Tel: +61 (8)9485 0990
Email:investor-relations@88energy.com
|
|
|
|
Fivemark Partners, Investor and
Media Relations
|
|
Michael Vaughan
|
Tel: +61 (0)422 602 720
|
|
|
EurozHartleys Ltd
|
|
Dale Bryan
|
Tel: +61 (8)9268 2829
|
|
|
Cavendish Capital Markets
Limited
|
Tel: +44 (0)207 220 0500
|
Derrick Lee
|
Tel: +44 (0)131 220 6939
|
Pearl Kellie
|
Tel: +44 (0)131 220 9775
|
Information required by ASX Listing Rule 5.4.3 - Lease
Schedules as at 30 September 2024
Appendix 5B
Mining exploration entity or oil and gas exploration
entity quarterly cash flow report
Name of entity
|
88 Energy Limited
|
ABN
|
|
Quarter ended ("current
quarter")
|
80 072 964 179
|
|
30 September 2024
|
Consolidated statement of cash
flows
|
Current quarter
$A'000
|
Year to date (9 months)
$A'000
|
|
1.
|
Cash flows from operating
activities
|
-
|
-
|
|
1.1
|
Receipts from customers
|
|
1.2
|
Payments for
|
-
|
-
|
|
|
(a) exploration &
evaluation
|
|
|
(b)
development
|
-
|
-
|
|
|
(c)
production
|
-
|
-
|
|
|
(d) staff
costs
|
(392)
|
(1,221)
|
|
|
(e) administration and
corporate costs
|
(308)
|
(1,465)
|
|
1.3
|
Dividends received (see
note 3)
|
-
|
-
|
|
1.4
|
Interest received
|
28
|
104
|
|
1.5
|
Interest and other costs of finance
paid
|
-
|
-
|
|
1.6
|
Income taxes paid
|
-
|
-
|
|
1.7
|
Government grants and tax
incentives
|
-
|
-
|
|
1.8
|
Other
|
-
|
-
|
|
1.9
|
Net
cash from / (used in) operating activities
|
(672)
|
(2,582)
|
|
|
|
2.
|
Cash flows from investing activities
|
-
|
-
|
|
2.1
|
Payments to acquire or
for:
|
|
|
(a) entities
|
|
|
(b) tenements
|
(427)
|
(1,398)
|
|
|
(c) property, plant and
equipment
|
-
|
-
|
|
|
(d) exploration &
evaluation
|
(2,043)
|
(23,197)
|
|
|
(e)
investments
|
-
|
-
|
|
|
(f) other
non-current assets
|
-
|
-
|
|
2.2
|
Proceeds from the disposal
of:
|
-
|
-
|
|
|
(a) entities
|
|
|
(b) tenements
|
-
|
-
|
|
|
(c) property, plant and
equipment
|
-
|
-
|
|
|
(d)
investments
|
-
|
-
|
|
|
(e) other non-current
assets
|
-
|
-
|
|
2.3
|
Cash flows from loans to other
entities
|
-
|
-
|
|
2.4
|
Dividends received (see
note 3)
|
-
|
-
|
|
2.5
|
Other - Joint Venture
Contributions
Other - Distribution from Project
Longhorn
Other - Return of Bond
|
224
670
-
|
3,205
1,897
-
|
|
2.6
|
Net
cash from / (used in) investing activities
|
(1,576)
|
(19,493)
|
|
|
|
3.
|
Cash flows from financing activities
|
-
|
9,696
|
|
3.1
|
Proceeds from issues of equity
securities (excluding convertible debt securities)
|
|
3.2
|
Proceeds from issue of convertible
debt securities
|
-
|
-
|
|
3.3
|
Proceeds from exercise of
options
|
-
|
-
|
|
3.4
|
Transaction costs related to issues
of equity securities or convertible debt securities
|
-
|
(670)
|
|
3.5
|
Proceeds from borrowings
|
-
|
-
|
|
3.6
|
Repayment of borrowings
|
-
|
-
|
|
3.7
|
Transaction costs related to loans
and borrowings
|
-
|
-
|
|
3.8
|
Dividends paid
|
-
|
-
|
|
3.9
|
Other (provide details if
material)
|
-
|
-
|
|
3.10
|
Net
cash from / (used in) financing activities
|
-
|
9,026
|
|
|
|
4.
|
Net
increase / (decrease) in cash and cash equivalents for the
period
|
|
|
|
4.1
|
Cash and cash equivalents at
beginning of period
|
7,882
|
18,183
|
|
4.2
|
Net cash from / (used in) operating
activities (item 1.9 above)
|
(672)
|
(2,582)
|
|
4.3
|
Net cash from / (used in) investing
activities (item 2.6 above)
|
(1,576)
|
(19,493)
|
|
4.4
|
Net cash from / (used in) financing
activities (item 3.10 above)
|
-
|
9,026
|
|
4.5
|
Effect of movement in exchange rates
on cash held
|
(125)
|
375
|
|
4.6
|
Cash and cash equivalents at end of period
|
5,509
|
5,509
|
|
5.
|
Reconciliation of cash and cash equivalents
at the end of the quarter (as shown in the
consolidated statement of cash flows) to the related items in the
accounts
|
Current quarter
$A'000
|
Previous quarter
$A'000
|
5.1
|
Bank balances
|
5,509
|
7,882
|
5.2
|
Call deposits
|
-
|
-
|
5.3
|
Bank overdrafts
|
-
|
-
|
5.4
|
Other (provide details)
|
-
|
-
|
5.5
|
Cash and cash equivalents at end of quarter (should equal
item 4.6 above)
|
5,509
|
7,882
|
6.
|
Payments to related parties of the entity and their
associates
|
Current quarter
$A'000
|
6.1
|
Aggregate amount of payments to
related parties and their associates included in
item 1
|
186
|
6.2
|
Aggregate amount of payments to
related parties and their associates included in
item 2
|
-
|
Note: if any amounts are shown in items 6.1 or 6.2, your
quarterly activity report must include a description of, and an
explanation for, such payments.
|
6.1 Payments relate to
Director and consulting fees paid to Directors. All transactions
involving directors and associates were on normal commercial
terms.
7.
|
Financing facilities
Note: the term
"facility' includes all forms of financing arrangements available
to the entity.
Add notes as necessary for an
understanding of the sources of finance available to the
entity.
|
Total facility amount at quarter
end
$US'000
|
Amount drawn at quarter end
$US'000
|
7.1
|
Loan facilities
|
-
|
-
|
7.2
|
Credit standby
arrangements
|
-
|
-
|
7.3
|
Other (please specify)
|
-
|
-
|
7.4
|
Total financing facilities
|
-
|
-
|
|
|
|
7.5
|
Unused financing facilities available at quarter
end
|
-
|
7.6
|
Include in the box below a
description of each facility above, including the lender, interest
rate, maturity date and whether it is secured or unsecured. If any
additional financing facilities have been entered into or are
proposed to be entered into after quarter end, include a note
providing details of those facilities as well.
|
|
8.
|
Estimated cash available for future operating
activities
|
$A'000
|
8.1
|
Net cash from / (used in) operating
activities (item 1.9)
|
(672)
|
8.2
|
(Payments for exploration & evaluation classified as investing
activities) (item 2.1(d))
|
(2,043)
|
8.3
|
Total relevant outgoings
(item 8.1 + item 8.2)
|
(2,715)
|
8.4
|
Cash and cash equivalents at quarter
end (item 4.6)
|
5,509
|
8.5
|
Unused finance facilities available
at quarter end (item 7.5)
|
-
|
8.6
|
Total available funding
(item 8.4 + item 8.5)
|
5,509
|
|
|
|
8.7
|
Estimated quarters of funding available (item 8.6 divided
by item 8.3)
|
2.03
|
Note: if the entity has reported positive relevant outgoings
(ie a net cash inflow) in item 8.3, answer item 8.7 as
"N/A". Otherwise, a figure for the estimated quarters of funding
available must be included in item 8.7.
|
8.8
|
If item 8.7 is less than
2 quarters, please provide answers to the following
questions:
|
|
8.8.1 Does
the entity expect that it will continue to have the current level
of net operating cash flows for the time being and, if not, why
not?
|
|
Answer:
The total outgoings are higher in Q3
than expected in subsequent quarters due to the final payments
associated with the Hickory flow test program. The entity does not
expect the same level of outgoings in Q4 2024 and 2025 and has more
than 12 months of funding available based upon the current activity
schedule. Funds available will be further increased when Burgundy
Xploration pays its outstanding cash call of ~US$4
million.
|
|
8.8.2 Has
the entity taken any steps, or does it propose to take any steps,
to raise further cash to fund its operations and, if so, what are
those steps and how likely does it believe that they will be
successful?
|
|
Answer:
There is no requirement to raise
further funds based on anticipated expenditure with ongoing
forecast cash distributions from Project Longhorn as well as ~US$4
million expected payment from Burgundy.
|
|
8.8.3 Does
the entity expect to be able to continue its operations and to meet
its business objectives and, if so, on what basis?
|
|
Answer:
The entity's business objectives are
on track with sufficient cash available as per the answers
above.
|
|
Note: where item 8.7 is less than 2 quarters, all of
questions 8.8.1, 8.8.2 and 8.8.3 above must be
answered.
|
1.1 Compliance
statement
1 This statement has
been prepared in accordance with accounting standards and policies
which comply with Listing Rule 19.11A.
2 This statement
gives a true and fair view of the matters disclosed.
Date:
29 October 2024
Authorised by: By the
Board
(Name of body or officer authorising
release - see note 4)
1.2
Notes
1. This
quarterly cash flow report and the accompanying activity report
provide a basis for informing the market about the entity's
activities for the past quarter, how they have been financed and
the effect this has had on its cash position. An entity that wishes
to disclose additional information over and above the minimum
required under the Listing Rules is encouraged to do so.
2. If
this quarterly cash flow report has been prepared in accordance
with Australian Accounting Standards, the definitions in, and
provisions of, AASB 6:
Exploration for and Evaluation of Mineral Resources and
AASB 107: Statement of Cash
Flows apply to this report. If this quarterly cash flow
report has been prepared in accordance with other accounting
standards agreed by ASX pursuant to Listing Rule 19.11A, the
corresponding equivalent standards apply to this report.
3.
Dividends received may be classified either as cash flows from
operating activities or cash flows from investing activities,
depending on the accounting policy of the entity.
4. If
this report has been authorised for release to the market by your
board of directors, you can insert here: "By the board". If it has
been authorised for release to the market by a committee of your
board of directors, you can insert here: "By the [name of board committee - eg Audit and Risk Committee]". If it
has been authorised for release to the market by a disclosure
committee, you can insert here: "By the Disclosure
Committee".
5. If
this report has been authorised for release to the market by your
board of directors and you wish to hold yourself out as complying
with recommendation 4.2 of the ASX Corporate Governance
Council's Corporate Governance
Principles and Recommendations, the board should have
received a declaration from its CEO and CFO that, in their opinion,
the financial records of the entity have been properly maintained,
that this report complies with the appropriate accounting standards
and gives a true and fair view of the cash flows of the entity, and
that their opinion has been formed on the basis of a sound system
of risk management and internal control which is operating
effectively.