REG - 88 Energy Limited - Quarterly Report and Appendix 5B
26/07/2024 07:00
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RNS Number : 8581X 88 Energy Limited 26 July 2024
26 July 2024
QUARTERLY ACTIVITIES REPORT
For the quarter ended 30 June 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 June 2024.
Highlights
Project Phoenix (~75% WI)
· Dual success at the 2024 Hickory-1 flow test program. Upper Slope
Fan System (USFS) and Shelf Margin Deltaic (SMD) reservoirs both flowed light
oil:
Ø USFS: produced at a peak flow rate of over 70 barrels of oil per day (bopd)
of light oil(1);
Ø SMD: produced at a peak flow rate of ~50 bopd of light oil(2); and
Ø Quality and deliverability of both reservoirs demonstrated via oil
production to surface with the USFS reservoir producing under natural flow.
· Hickory-1 advancement activities are currently focused on:
Ø Post-well testing and analysis, expected to be completed in Q3 2024;
Ø Securing an independent Contingent Resource for the SFS and SMD reservoirs,
based on the production of hydrocarbons to surface, targeting Q4 2024
delivery;
Ø Undertaking a formal farm-out process to attract a quality partner to fund
the next stage of the appraisal and development at Project Phoenix; and
Ø Planning and design for a potential horizontal flow test and early stage
production system.
· Successful outcomes from the Hickory-1 flow test delivered a
platform for monetisation of Project Phoenix, justifying further advancement,
with key benefits including:
Ø Potential capital-light modular Early Production System;
Ø Expected production from analagous long horizontal wells typically produce
6 to 12 times higher flow rates than vertical wells; and
Ø An ability to produce concurrently from multiple reservoirs in a single
development scenario.
Project Leonis (100% WI)
· Maiden prospective resource estimate for Upper Schrader Bluff
(USB) of net mean 381 million barrels of oil, completed in June 2024(3,4.)
· Permitting and planning commenced for the newly named Tiri-1
exploration well, designed to test the Tiri prospect in the USB formation.
· Farm-out process underway to secure a funding partner ahead of
potential drilling of the Tiri-1 well in 2026.
Namibia PEL 93 (20% WI)
· Fully funded 2D seismic acquisition program completed in July
2024, successfully acquiring 203-line km of 2D seismic data on time and within
budget.
· Data processing is ongoing, both in the field and at Earth Signal
Processing in Calgary, with final interpretation expected by Q4 2024.
· Program outcomes are set to include:
Ø Validation of up to 10 independent structural closures;
Ø Delivery of a maiden certified Prospective Resource estimate; and
Ø Identification of future potential drilling locations targeting the Damara
play.
Project Longhorn (~65% WI)
· Four planned workovers successfully completed in line with budget
and production underway:
Ø Delivered increase in production from 328 BOE per day (average Q1 2024,
~62% oil) to Q2 2024 average of 395 BOE per day (~63% oil), with production
for June averaging 456 BOE per day.
Ø Workover production declines currently lower than initially forecast.
· Company received June 2024 cash flow distribution of A$0.5M,
post-workover expenditure.
Corporate
· Cash balance of A$7.9 million, with ~90% of Hickory-1 flow test
payments made and the remainder expected to be paid in July 2024.
· Successful oversubscribed share placement raising A$9 million
(after costs) to support the Hickory-1 flow test, post-flow test studies,
advancement and commercialisation activities at Project Phoenix, exploration
activities across Namibia and Alaska (including permitting and planning for
Project Leonis' Tiri-1 exploration well) and farmout costs.
· Budget for the forward twelve-month activity schedule fully
funded for delivery.
1. Refer announcement released to ASX on 2 April 2024 for further details
2. Refer announcement released to ASX on 15 April 2024 for further details
3. Refer announcement released to ASX on 4 June 2024 for further details
including cautionary statement
4. Cautionary Statement: 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.
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 offset
drilling and testing. Project Phoenix is strategically located on the Dalton
Highway with the Trans-Alaskan Pipeline System bisecting the acreage.
The Hickory-1 discovery well was drilled in February 2023 and flow tested the
following Alaskan winter season in Q1/Q2 2024. The testing operations focussed
on the two shallower primary targets, the SFS and SMD reservoirs. Of the SFS
series of reservoirs, the Upper SFS (USFS) reservoir was targeted to be flow
tested as it had not been previously tested, whereas the Lower SFS has
previously been flow tested and therefore the producibility of that reservoir
was confirmed on adjacent acreage. The USFS 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 (USFS) flow test results
The USFS produced at a peak flow rate of ~70 bopd. Oil cuts increased
throughout the flow back period as the well cleaned up, reaching a maximum of
15% oil cut. The Company expects that oil rates and cut would have likely
increased further had the test period been extended. The well produced at an
average oil flow rate of ~42 bopd during the natural flow back period, with
instantaneous rates ranging from ~10-77 bopd and 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 assisted lift.
Multiple oil samples were recovered with measured oil gravities of 39.9 to
41.4 API (representing a light crude oil). For full details of the USFS test
results please refer to the ASX announcement dated 2 April 2024.
SMD-B flow test results
The SMD-B produced at a peak 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 as the well continued to clean up.
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 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 production rate with a low gas to oil ratio. For full
details in relation to the SMD-B test results please refer to the ASX
announcement dated 15 April 2024.
Post-flow testing and next steps
Pressurised oil samples collected during both the USFS and SMD tests were
transported to laboratories for further analysis. The analyses are expected to
verify the reservoir fluid characteristics.
Following completion of the lab analyses, 88E will commission an Independent
Contingent Resource assessment for the Upper SFS, Lower SFS and SMD-B. This
assessment is expected to be completed in Q4 2024.
Results from the post-flow test analyses will assist 88E in the optimisation
and design of the next phase of advancement at Project Phoenix. The Company,
together with its Project Phoenix Joint Venture partner, are currently
assessing locations for the drilling of a horizontal well, including the
Franklin Bluffs gravel pad location (previously utilised for the Icewine 1 and
2 unconventional test wells), where a long-term flow test of either the SFS or
SMD reservoirs may be undertaken.
The Company also plans to commence a formal farmout process prior to the
future drilling of a horizontal well and development of the Project Phoenix
acreage, with the aim of attracting a strategic partner for the next stage of
commercialisation. The table is an indicative timeline for Project Phoenix
development;
Joint Venture Partner Update
JV Partner Burgundy Xploration, LLC (Burgundy) paid its outstanding 2023 cash
calls and signed the flow test authorised for expenditure (AFE) on 15 February
2024 as part of the standstill agreement that was entered into at the end of
2023 with the Company's 100%-owned subsidiary Accumulate Energy Alaska, Inc
(88E-Accumulate). The standstill agreement allows Burgundy six (6) months to
pay its share of the AFE cost (~US$3m) by 15 August 2024 (flow test cash
call). Burgundy will pay its share of the flow test cash call from either (1)
the proceeds of a public listing which Burgundy is pursuing; (2) the proceeds
of a private capital raise; or (3) if Burgundy has not made payment for its
flow test cash call by 15 August 2024, then Burgundy will be required to
transfer 50% its working interest in the Toolik River Unit (TRU) leases to
88E-Accumulate.
At the time of this announcement Burgundy has paid contributions towards lease
rentals in Q2 2024, with the balance of funds due outstanding. The Company
understands Burgundy is in advanced stages of negotiations to secure funding
under options (1) and (2) noted above. Burgundy is aiming to secure sufficient
funding via its public listing to pay all outstanding cash call amounts due to
88E-Accumulate, and to secure funds sufficient to acquire an additional
working interest in Project Phoenix from 88 Energy and potentially
Operatorship to take the project to the next phase of activity which includes
a planned horizontal well test.
Burgundy understands that under the current standstill agreement, if payment
of the flow test cash call is not made by15 August 2024, this will require
Burgundy to transfer to 88E-Accumulate 50% of Burgundy's working interest
Project Phoenix's Toolik River Unit leases.
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.
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 on 4 June 20241.
The initial total Prospective Resource estimate follows a review period of an
extensive data suite that included 3D and 2D seismic data, well logs from Hemi
Springs Unit-3 and Hailstorm-1, as well as nearby wells adjacent to the
Project Leonis acreage, along with extensive petrophysical analysis and
mapping.
Importantly, the USB formation is the same proven producing zone as 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
88 Energy has engaged Fairweather to assist in commencing the planning and
permitting 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, in order to reduce costs.
Timing for the drilling of the Tiri-1 exploration well is dependent on
securing a successful farm-out partner.
The Company has secured Stellar Energy Advisors Limited (Stellar) in London to
manage the farm-out process, who have been engaged with multiple parties in
advancing the assessment of the farm-out opportunity. The process remained
ongoing at the end of the quarter.
1. Refer announcement released to ASX on 4 June 2024 for further details
including cautionary statement
Namibia PEL 93 (20% WI)
In February 2024, the Company announced a 20% WI transfer by operator Monitor
Exploration Limited (Monitor) to 88 Energy in relation to PEL 93 located in
the Owambo Basin. Monitor holds 55% WI with 25% shared across local entities,
Legend Oil Namibia Pty Ltd and NAMCOR.
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.
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. Historical assessment utilised a combination
of techniques and interpretation of legacy data to identify the Owambo Basin
as having significant exploration potential. Monitor 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, identifying ten (10)
independent structural closures from airborne geophysical methods and partly
verified these using existing 2D seismic coverage.
In May 2024, the Company announced that Polaris Natural Resources Development
Ltd (Polaris) was awarded the next stage for PEL 93, the 2D seismic
acquisition program contract. Polaris mobilised vibroseis units and recording
equipment to location in late June 2024 and successfully acquired 203-line km
of 2D seismic data in July 2024 with data processing ongoing, both in-field
and at Earth Signal Processing in Calgary with final interpretation
anticipated to be finalised in Q4 2024.
Results of the new 2D seismic acquisition will be integrated with existing
historical exploration data to refine current prospect interpretation.
Expected program outcomes include:
Ø Validate up to 10 independent structural closures.
Ø Maiden certified prospective resource estimate.
Ø Identification of future potential drilling locations targeting the Damara
play.
Project Longhorn (~65% WI)
The Joint Venture (Bighorn JV), 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, agreed to
a development program that included five (5) workovers in 1H 2024.
During the quarter, the Bighorn JV successfully executed and commenced
production from four of the planned five workovers in line with Budget. The
first workover production commenced in mid-April, the second and third
commenced in mid-May and the fourth workover production began in the final
week of June 2024. Completion of the workovers increased production from 328
BOE per day (average Q1 2024, ~62% oil) to Q2 2024 average of 395 BOE per day
(~63% oil), with production for June averaging 456 BOE per day. Workover
declines are currently lower than initially forecast. The final planned
workover encountered a tubing fish not recorded in the well file. The operator
tried several tools but could only clean out 75 feet of the anticipated 1,500
feet of the tubing fish recovered. The Joint Venture decided to suspend
operations and P&A the workover with sunk CAPEX capped at A$0.5M compared
to a budget of A$1.2M.
The Company received a cash flow distribution of A$0.5M in June 2024
post-workover expenditure.
Peregrine & Umiat (100% WI)
88 Energy was successful in receiving 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 to Umiat Unit and leases on the same basis as Project Peregrine
suspension, requesting an initial 1-year suspension that will be reviewed as
required during which time 88 Energy will persist with the refinement of
internal geological and geophysical models/interpretation. If the suspension
is approved, it will also relieve 88 Energy of the obligation to pay Umiat
lease rentals during the suspension period of ~A$0.1 million due in Q4.
Future exploration efforts in the Peregrine/Umiat area are subject to a
resolution in the current consultation process concerning future regulations
in the NPRA and the Company securing a farm-out.
Corporate
On 24 April 2024, the Company successfully completed an oversubscribed share
placement to domestic and international institutional and sophisticated
investors to raise gross A$9.9 million (approx. £5.23 million) before costs
(Placement). 3,291,974,839 new fully paid ordinary shares in the Company (the
New Ordinary Shares) were issued at an issue price of A$0.003 (£0.0016) per
New Ordinary Share (the Issue Price). The net proceeds augmented the Company's
existing cash balance to fund:
· Hickory-1 discovery well flow test operations at Project Phoenix,
post-well studies, securing a contingent resource for the SFS and SMD
reservoirs and other costs associated with commercialising Project Phoenix;
· Exploration activities including lease rentals across Alaska and
Namibia acreage;
· Permit and planning costs for Tiri-1 exploration well at Project
Leonis; and
· Farmout process to advance projects at Project Phoenix and
Project Leonis.
Euroz Hartleys Limited (Euroz Hartleys) acted as Sole Lead Manager and
Bookrunner to the Placement. Cavendish Capital Markets Ltd (Cavendish) acted
as Nominated Adviser and Sole Broker to the Placement in the United Kingdom.
Inyati Capital Pty Ltd (Inyati) acted as Co-Manager to the Placement.
Commission for the Placement was 6% (plus GST) of total funds raised across
Euroz Hartleys, Inyati and Cavendish. In addition, and subject to shareholder
approval, the Company will issue a total of 75,000,000 Unlisted Options
(exercisable at A$0.0055 on or before the date which is 3 years from the date
of issue) to Euroz Hartleys, Cavendish and Inyati.
During the quarter, Monitor agreed to receive 88 Energy shares as settlement
for the fourth and final Stage 1 instalment of the farm-in agreement, as
announced to the ASX on 13 November 2023. This instalment covers the remaining
back costs and the 2024 work program carry of US$0.92 million through the
issuance of 476,634,546 new ordinary 88 Energy Shares (at a deemed issue price
of A$0.003 per share).
The New Ordinary Shares were issued under the Company's available placement
capacity pursuant to Listing Rule 7.1 and are not subject to shareholder
approval. The Ordinary Shares ranked pari passu with the existing ordinary
shares in the Company and the Ordinary Shares were admitted to trading on AIM.
Following the issue of the New Ordinary Shares pursuant to the Placement and
the final stage 1 shares issued to Monitor, the Company had 28,892,671,952
ordinary shares on issue, all of which have voting rights.
The Company held its Annual General Meeting on 13 May 2024 and all six (6)
resolutions were carried.
Finance
As at 30 June 2024, the Company's cash balance was A$7.9M.
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$17.3M (March 2024
quarter: A$3.9M) predominantly related to paying for ~70% of the Hickory-1
flow test program in Q2. Approximately 90% of Hickory-1 flow test payments
have now been made, with the remainder expected to be paid in July 2024.
· Administration, staff, and other costs of A$1.1M (March 2024
quarter: A$0.8M) which including fees paid to Directors and consulting fees
paid to Directors of A$0.2M. Net of one off annual costs of ~A$0.3M which
included corporate insurance, audit and taxation services across 88 Energy
Group, general and administration costs were in line with the prior quarter.
· Additional cost reductions identified and implemented across
corporate overheads, including reductions in salary costs, with the Company
already realising the benefits of these reductions in 1H 2024 (HY'24 totalled
A$1.91M compared to HY'23 totalled A$2.94M - a saving of A$1.03M).
Information required by ASX Listing Rule 5.4.3
Project Name Location Interest at beginning of Quarter Interest at end of Quarter
Net Area (acres)
Phoenix(2) Onshore, North Slope Alaska 44,562 ~75% ~75%
Icewine West(2) Onshore, North Slope Alaska 83,611 ~75% ~75%
Peregrine(1) 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%
Umiat 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
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
Fivemark Partners, Investor and Media Relations
Michael Vaughan Tel: +61 (0)422 602 720
EurozHartleys Ltd
Dale Bryan Tel: +61 (0)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 June
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 June 2024
Consolidated statement of cash flows Current quarter Year to date (6 months)
$A'000
$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 (430) (829)
(e) administration and corporate costs (751) (1,157)
1.3 Dividends received (see note 3) - -
1.4 Interest received 39 76
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 (1,142) (1,910)
2. Cash flows from investing activities - -
2.1 Payments to acquire or for:
(a) entities
(b) tenements (818) (971)
(c) property, plant and equipment - -
(d) exploration & evaluation (17,303) (21,154)
(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 107 2,981
Other - Distribution from Project Longhorn 512 1,227
Other - Return of Bond - -
2.6 Net cash from / (used in) investing activities (17,502) (17,917)
3. Cash flows from financing activities 9,696 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 (670) (670)
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 Net cash from / (used in) financing activities 9,026 9,026
4. Net increase / (decrease) in cash and cash equivalents for the period
4.1 Cash and cash equivalents at beginning of period 17,502 18,183
4.2 Net cash from / (used in) operating activities (item 1.9 above) (1,142) (1,910)
4.3 Net cash from / (used in) investing activities (item 2.6 above) (17,502) (17,917)
4.4 Net cash from / (used in) financing activities (item 3.10 above) 9,026 9,026
4.5 Effect of movement in exchange rates on cash held (2) 500
4.6 Cash and cash equivalents at end of period 7,882 7,882
5. Reconciliation of cash and cash equivalents Current quarter Previous quarter
at the end of the quarter (as shown in the consolidated statement of cash
$A'000
$A'000
flows) to the related items in the accounts
5.1 Bank balances 7,882 17,502
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) 7,882 17,502
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 205
in item 1
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 remuneration and consulting fees paid to
Directors. All transactions involving directors and associates were on normal
commercial terms.
7. Financing facilities Total facility amount at quarter end Amount drawn at quarter end
Note: the term "facility' includes all forms of financing arrangements
$US'000
$US'000
available to the entity.
Add notes as necessary for an understanding of the sources of finance
available to the entity.
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) (1,142)
8.2 (Payments for exploration & evaluation classified as investing activities) (17,303)
(item 2.1(d))
8.3 Total relevant outgoings (item 8.1 + item 8.2) (18,445)
8.4 Cash and cash equivalents at quarter end (item 4.6) 7,882
8.5 Unused finance facilities available at quarter end (item 7.5) -
8.6 Total available funding (item 8.4 + item 8.5) 7,882
8.7 Estimated quarters of funding available (item 8.6 divided by item 8.3) 0.4
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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 Q2 due to final payments associated with the
Hickory flow test program. There is approximately A$1.5 million to pay in Q3.
The entity does not therefore expect the same level of outgoings in Q3 and Q4
and has 9.7 quarters of funding available based upon the current activity
schedule.
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:
Based on anticipated expenditure under the current activity schedule and cash
distributions from Project Longhorn, the entity anticipates being funded for
9.7 quarters. If the planned activity schedule should change, then the entity
will take steps to obtain additional funding.
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:
Based on anticipated expenditure under the current activity schedule and cash
distributions from Project Longhorn, the entity anticipates being funded for
9.7 quarters
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: 26 July 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.
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