18 April 2024
QUARTERLY ACTIVITIES
REPORT
For the quarter ended 31
March 2024
88 Energy Limited (ASX:88E, AIM:88E,
OTC:EEENF) (88 Energy, 88E
or the Company) provides
the following report for the quarter ended 31 March
2024.
Highlights
Project Phoenix (~75% WI)
· Successful Hickory-1 discovery well flow test and stimulation
program (Flow Test)
conducted during March and April 2024.
· Upper
Slope Fan System (USFS)
produced at a peak flow rate of over 70
barrels of oil per day (bopd) of light oil, with multiple oil shows
measuring ~40-degree API oil gravity.
· Subsequent to quarter end the Shelf Margin Deltaic
(SMD) produced at a peak
flow rate of ~ 50 barrels of oil per day (bopd) of light oil, with
multiple oil shows measuring ~39-degree API oil gravity.
· Quality and deliverability of both SMD-B and USFS demonstrated
via oil production to surface with the USFS reservoir producing
under natural flow - positively differentiating Hickory-1 from
results on adjacent acreage.
· It is
anticipated that these reservoirs would be developed from long
horizontal production wells which typically produce at multiples of
between 6 to 12 times higher than vertical wells. Project Phoenix
also benefits from the ability to produce concurrently from
multiple reservoirs in a single development scenario.
· Independent Contingent Resource declaration to be sought for
both the Upper SFS and Lower SFS reservoirs, as well as the SMD
reservoirs, based on the flow of hydrocarbons to
surface.
· JV
Partner Burgundy Xploration, LLC (Burgundy) transferred remaining
outstanding 2023 cash call amount due of US$1.75 million and
remains committed to the Hickory-1 flow test authorised funding
expenditure (AFE).
Managing Director, Ashley Gilbert,
commented on Project Phoenix:
"In what has proven to be a pivotal quarter for 88 Energy and
its shareholders, we achieved the successful flow of oil to
surface, for the first time, from the previously untested USFS
reservoir and also subsequent to quarter end from the shallower
SMD-B reservoir, both at our Hickory-1 discovery well. This
represents a tremendous achievement that adds immediate value to
Project Phoenix and unlocks multiple pathways for future
commercialisation.
With flow testing operations complete, we will now transition
to post well analysis and are moving to secure further Contingent
Resources at Project Phoenix.
We
expect to commence a formal farm-out process for Project Phoenix
following completion of the Hickory-1 post flow test analysis, with
the aim of attracting a strategic partner for the next stage of
development and commercialisation."
Namibia PEL 93 (20% WI)
· Transfer of 20% working interest in Petroleum Exploration
Licence 93 (PEL
93) complete, being the first
stage of a three-stage farm-in agreement following approval by the
Namibian Ministry of Mines and Energy.
· PEL 93
includes an extensive lead portfolio with ten significant
independent structural closures identified from a range of
geophysical and geochemical techniques and potential for more leads
to be identified as dataset is expanded.
· Seismic acquisition is planned for mid-2024 with potential
initial exploration well targeting the Damara play as early as H2
CY2025.
Project Leonis (100% WI)
· Maiden
prospective resource estimate for Upper Schrader Bluff (USB) reservoir expected H1
2024.
· Farm-out process commenced with multiple parties engaged and
reviewing data room materials, ahead of potential drilling of a new
well in 2025/2026.
Project Longhorn (~64% WI)
· Two of
the planned five workovers scheduled to be in completed in 1H 2024
are underway and are currently projected to be delivered under
budget.
· Q1
2024 production steadily averaged 328 BOE per day gross (~62%
oil).
· Company received cash flow distribution of A$0.7M in March
2024.
· The
Company also reduced it's working interest in 9 leases during the
quarter by an average of a ~7% reduction in net WI's across these
leases. Consideration for these leases totalled A$0.3M.
Corporate
·
Cash balance of A$17.5 million and no debt (as at 31
March 2024), ~20% of Hickory-1 flow test payments have been made,
with the remainder expected to be paid in Q2 2024.
· Net
cash outflows in relation to operating expenses for Q1 2024
totalling A$0.77M as compared to A$1.44M in Q4 2023.
· Cost
reduction initiatives commenced in the quarter targeting a
reduction in salary and overhead costs. Further business
optimisation activities underway, aimed at preserving and enhancing
value for shareholders and advancement of key projects.
Project Phoenix (~75% WI)
Project Phoenix is focused on
oil-bearing conventional reservoirs identified during the drilling
and logging of Icewine-1 and Hickory-1 and adjacent offset drilling
and testing. Project Phoenix is strategically located on the
Dalton Highway with the Trans-Alaskan Pipeline System running
through the acreage.
The Hickory-1 discovery well was
previously drilled in February 2023. All American Oilfield's
upgraded Rig-111 was subsequently secured in September 2023 to
conduct the flow test. During the March 2024 quarter, ice road and
pad construction works were completed and the rig was subsequently
mobilised. Flow test operations commenced in March 2024.
The testing operations focussed on
the two primary targets, the SFS
and SMD
reservoirs. Of the SFS series of reservoirs, the
Upper SFS reservoir was targeted to be flow tested as it has not
been previously tested, whereas the Lower SFS has previously been
flow tested and producibility of that reservoir confirmed on
adjacent acreage. The Upper SFS was followed by a targeted testing
of the SMD-B reservoir. Each zone was independently isolated,
stimulated and flowed to surface using nitrogen lift to assist in
an efficient clean-up of the well.
Upper SFS flow
test results
A 20ft perforated interval in the
Upper SFS reservoir was stimulated via a single fracture stage of
241,611 lbs proppant volume. The well was cleaned-up and flowed for
111 hours in total, of which 88 hours was under natural flow back
and 23.5 hours utilising nitrogen lift.
The
USFS test produced at a peak flow rate of over ~70 bopd. Oil cuts
increased throughout the flow back period as the well cleaned up,
reaching a maximum of 15% oil cut at the end of the flow test
program. The Company expects that oil rates and cut would have
likely increased further should the test period have been extended.
The well produced at an average oil flow rate of approximately 42
bopd during the natural flow back period (with established
production rates occurring over an ~11 hour test period,
accumulating ~19bbls of oil. An additional ~6bbls of oil was
recovered outside of the established production period), with
instantaneous rates ranging from approximately 10 - 77 bopd with
average rates increasing through the test period.
Importantly, the USFS zone flowed oil to surface under
natural flow, with flow back from other reservoirs in adjacent
offset wells only producing under nitrogen lift. A total of
3,960bbls of fluid was injected into the reservoir and 2,882bbls of
water was recovered during the flow back period, most of which was
injection fluid. Total flow rates (inclusive of recovery of frac
fluid) averaged ~600 bbl/d over the duration of the flow
back.
Multiple oil samples were recovered
with measured oil gravities of between 39.9 to 41.4 API
(representing a light crude oil).
Additionally, some natural gas
liquids ("NGLs") were produced but not measured, as was anticipated
in the planning phase. The presence of NGLs was demonstrated by
samples from the flare line and by visible black smoke in the
flare. Historically, NGL prices on the North Slope of Alaska have
been similar or slightly below light oil prices and are therefore
considered highly valuable. Further work is required to quantify
the exact volume of NGLs, which 88 Energy intends to include as
part of a maiden certified Contingent Resource assessment at
Project Phoenix for the SFS reservoirs.
For full details in relation to the
Upper SFS test results please refer to the ASX announcement dated 2
April 2024.
SMD-B flow test results (subsequent
to quarter end)
A
20ft perforated interval in the SMD-B reservoir was stimulated via
a single fracture stage comprising 226,967 lbs of proppant volume.
The well was cleaned-up and flowed for 84 hours in total, utilising
nitrogen lift throughout the entire test period. The average fluid
flow rate over the duration of the flow back period was
approximately 445 bbls/d, with choke sizes ranging from 8/64ths to
33/64ths.
The SMD-B test produced at a peak
estimated flow rate of ~50 bopd. Oil cuts varied throughout the
flow back period, reaching a maximum of 10% oil cut. The well
produced at an average oil cut of 4% following initial oil to
surface, with instantaneous rates observed during the 16-hour
period varying as the well continued to clean up. Total stimulation
load water was not recovered and water salinity measurements
indicated we were recovering load water at the conclusion of the
test. Unlike flow tests on adjacent acreage where multiple gas lift
mandrels and valves were used in completions designs, and nitrogen
was unloaded in the tubing in stages up the well bore, Hickory-1
utilised a single gas lift mandrel where nitrogen was introduced
via one valve at the deepest section. This is viewed as positive
indication for future potential rates and performance.
Multiple oil samples were recovered,
with measured oil gravities of between 38.5 to 39.5 API,
representing a light crude oil.
Importantly, the SMD-B zone flowed
oil to surface with little to no measurable gas, representing a low
GoR production rate. Pressurised oil samples collected during
both the USFS and SMD tests will be transported to laboratories for
further analysis.
The SMD-B flow test was concluded
with sufficient information for the next steps, and the data
recorded will assist 88E in optimisation and design processes in
the next phase of advancement of Project Phoenix.
For full details in relation to the
SMD-B test results please refer to the ASX announcement dated 15
April 2024.
Namibia PEL 93 (20% WI)
In February 2024, the Company
announced the successful 20% WI transfer by Monitor Exploration
Limited (Monitor)
to 88 Energy in relation to PEL 93
located in the Owambo Basin, Namibia following
receipt approval from the Ministry of Mines and Energy.
The Company, via its wholly-owned
Namibian subsidiary, previously executed a three-stage farm-in
agreement in November 2023 for up to a 45% non-operated working
interest in onshore Petroleum Exploration Licence (PEL 93), which
covers 18,500km2
of underexplored ground within the Owambo Basin in
Namibia (refer to ASX announcement dated 13 November
2023).
Under the terms of the agreement, 88
Energy may earn up to a 45% working interest by funding its share
of agreed costs under the 2023-2024 approved work program and
budget as defined in the Farm-In Agreement (2024 Work Program) and
any future work program budgets yet to be agreed. The maximum total
investment by the Company is anticipated to be US$18.7
million.
The current and potential future PEL
93 Joint Venture partners and working interests are as
follows:
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 than 88 Energy's Alaskan portfolio and
more than 70 times larger than Project Phoenix.
Recent drilling results on nearby
acreage has highlighted the potential of a new and underexplored
conventional oil and gas play in the Damara Fold belt, referred to
as the Damara Play. Historical assessment utilised a combination of
techniques and interpretation of legacy data to identify the Owambo
Basin, and specifically blocks 1717 and 1817, as having significant
exploration potential.
Monitor has utilised a range of
geophysical and geochemical techniques to assess and validate the
significant potential of the acreage since award of PEL 93 in 2018.
It has identified ten (10) independent structural closures from
airborne geophysical methods and partly verified these using
existing 2D seismic coverage. Further, ethane concentration
measured in soil samples over interpreted structural leads
validates the existence of an active petroleum system, with passive
seismic anomalies also aligning closely to both interpreted
structural leads and measured alkane molecules (c1-c5)
concentrations in soil.
The forward work-program will start
with a low impact ~200 line-kilometre 2D seismic program focusing
on confirming the structural closures of the 10 independent leads
identified. The 2D seismic program will be conducted in mid-2024
following a period of planning, public consultation, updating of
environmental compliance requirements and relevant approvals.
Results from the 2D seismic program will then be incorporated into
existing historical exploration data over the acreage, with results
used to identify possible exploration drilling
locations.
Project Longhorn (~65% WI)
In December 2023, the Joint Venture
(Bighorn JV),
Bighorn Energy LLC (Bighorn) which comprises Longhorn
Energy Investments LLC (LEI) a 100% wholly owned subsidiary of
88 Energy with 75% ownership and Lonestar I, LLC
(Lonestar or
Operator)
with remaining 25% ownership, finalised its 2024
work program and budget. The Bighorn JV agreed to a development
program that included 5 workovers in 1H 2024 and 2 new wells in 2H
2024, contingent on successful workovers.
During the quarter, the Bighorn JV
commenced two of the planned five workovers with assessment of
production occuring during April 2024.
Q1 2024 production averaged a fairly
steady 328 BOE per day gross (~62% oil) which was slightly below
the budgeted volume of 346 BOE per day gross (65% oil) due to
January winter storms and the Company received a cash flow
distribution of A$0.7M in March 2024.
The Bighorn JV executed a ~10%
sell-down (gross, ~7% net to 88 Energy) of the 2023 acquired
acreage, in order to re-disk and accelerate development
opportunities. The transaction realised acquisition payments of
~A$0.3M and the non-operated partners will contribute their share
of the capital development costs coupled with a 25% carry of their
ownership share on the five 2024 WP&B agreed
workovers.
Qualified Petroleum Reserves Evaluator
Statement
The information in this evaluation
that relates to Project Longhorn is based on, and fairly
represents, information and supporting documentation prepared by
Paul Griffith of consultants PJG Petroleum Engineers LLC. Mr
Griffith holds a BSc. and a Master's in Petroleum Engineering, is a
member of the Society of Petroleum Engineers (SPE) and has over 35
years of reservoir and petroleum engineering experience. Mr
Griffith is not an employee of the Company. Mr Griffith has
reviewed this document as to its form and context in which the
reserves and the supporting information are presented and consent
to its release.
The information in this evaluation
that relates to the Umiat oil field has not changed since first
reporting to the ASX on 11 January 2021, and fairly represents,
information and supporting documentation prepared by technical
employees of consultants Ryder Scott Company LP, under the
supervision of Dr Stephen Staley, as stated in that announcement.
Dr Staley 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 resource and
reserve 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.
Reserves Cautionary Statement
Oil and gas reserves and resource
estimates are expressions of judgment based on knowledge,
experience and industry practice. Estimates that were valid when
originally calculated may alter significantly when new information
or techniques become available. Additionally, by their very nature,
reserve and resource estimates are imprecise and depend to some
extent on interpretations, which may prove to be inaccurate. As
further information becomes available through additional drilling
and analysis, the estimates are likely to change. This may result
in alterations to development and production plans which may, in
turn, adversely impact the Company's operations. Reserves estimates
and estimates of future net revenues are, by nature, forward
looking statements and subject to the same risks as other
forward-looking statements.
Corporate
The Company held a General Meeting
on 15 January 2024 and all 11 resolutions were passed without
amendment on a poll.
Finance
As at 31 March 2024, the Company's
cash balance is A$17.5M.
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$3.9M (December
2023 quarter: A$2.8M) predominantly related to the Hickory-1 flow
test program. Approximately 20% of Hickory-1 flow test payments
have been made, with the remainder expected to be paid in Q2
2024.
· Administration, staff, and other costs of A$0.7M (December
2023 quarter: A$1.4M). Including fees paid to Directors and
consulting fees paid to Directors of A$0.2M.
· Cost
reduction initiatives commenced in the quarter targeting a
reduction in salary and overhead costs. Further business
optimisation activities underway, aimed at preserving and enhancing
value for shareholders and advancement of key projects.
Information required by ASX Listing Rule
5.4.3
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
Tel: +61 (0)8 9485 0990
Email:investor-relations@88energy.com
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Fivemark Partners, Investor and
Media Relations
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Michael Vaughan
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Tel: +61 (0)422 602 720
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EurozHartleys Ltd
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Dale Bryan
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Tel: +61 (0)8 9268 2829
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Cavendish Capital Markets Limited
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Tel: +44 (0)207 220 0500
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Derrick Lee
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Tel: +44 (0)131 220 6939
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Pearl Kellie
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Tel: +44 (0)131 220 9775
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1. Refer announcement released to ASX on 21
December 2023 regarding Project Peregrine 12-month suspension until
30 November 2024
Information required by ASX Listing Rule 5.4.3 - Lease
Schedules as at 31 March 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
|
|
31 March 2024
|
Consolidated statement of cash
flows
|
Current quarter
$A'000
|
Year to date (3 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
|
(399)
|
(399)
|
|
|
(e) administration and
corporate costs
|
(406)
|
(406)
|
|
1.3
|
Dividends received (see
note 3)
|
-
|
-
|
|
1.4
|
Interest received
|
37
|
37
|
|
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
|
(768)
|
(768)
|
|
|
|
2.
|
Cash flows from investing activities
|
-
|
-
|
|
2.1
|
Payments to acquire or
for:
|
|
|
(a) entities
|
|
|
(b) tenements
|
(153)
|
(153)
|
|
|
(c) property, plant and
equipment
|
-
|
-
|
|
|
(d) exploration &
evaluation
|
(3,851)
|
(3,851)
|
|
|
(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
|
2,874
715
-
|
2,874
715
-
|
|
2.6
|
Net
cash from / (used in) investing activities
|
(415)
|
(415)
|
|
|
|
3.
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Cash flows from financing activities
|
-
|
-
|
|
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
|
-
|
-
|
|
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
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Net
cash from / (used in) financing activities
|
-
|
-
|
|
|
|
4.
|
Net
increase / (decrease) in cash and cash equivalents for the
period
|
|
|
|
4.1
|
Cash and cash equivalents at
beginning of period
|
18,183
|
18,183
|
|
4.2
|
Net cash from / (used in) operating
activities (item 1.9 above)
|
(768)
|
(768)
|
|
4.3
|
Net cash from / (used in) investing
activities (item 2.6 above)
|
(415)
|
(415)
|
|
4.4
|
Net cash from / (used in) financing
activities (item 3.10 above)
|
-
|
-
|
|
4.5
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Effect of movement in exchange rates
on cash held
|
502
|
502
|
|
4.6
|
Cash and cash equivalents at end of period
|
17,502
|
17,502
|
|
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
|
17,502
|
18,182
|
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)
|
17,502
|
18,182
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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
|
214
|
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)
|
(768)
|
8.2
|
(Payments for exploration & evaluation classified as investing
activities) (item 2.1(d))
|
(3,851)
|
8.3
|
Total relevant outgoings
(item 8.1 + item 8.2)
|
(4,619)
|
8.4
|
Cash and cash equivalents at quarter
end (item 4.6)
|
17,502
|
8.5
|
Unused finance facilities available
at quarter end (item 7.5)
|
-
|
8.6
|
Total available funding
(item 8.4 + item 8.5)
|
17,502
|
|
|
|
8.7
|
Estimated quarters of funding available (item 8.6 divided
by item 8.3)
|
3.8
|
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: n/a
|
|
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: n/a
|
|
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: n/a
|
|
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.
|
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:
18 April 2024
Authorised by: By the
Board
(Name of body or officer authorising
release - see note 4)
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.