Quarterly Report and Appendix 5B

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 oil¹;

Ø SMD: produced at a peak flow rate of ~50 bopd of light oil²; 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	Net Area (acres)	Interest at beginning of Quarter	Interest at end of Quarter
Phoenix2	Onshore, North Slope Alaska	44,562	~75%	~75%
Icewine West2	Onshore, North Slope Alaska	83,611	~75%	~75%
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%
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: [phone] Email:[e-mail]
Fivemark Partners, Investor and Media Relations
Michael Vaughan	Tel: [phone]
EurozHartleys Ltd
Dale Bryan	Tel: [phone]
Cavendish Capital Markets Limited	Tel: [phone]
Derrick Lee	Tel: [phone]
Pearl Kellie	Tel: [phone]

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 $A'000	Year to date (6 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	(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 Other - Distribution from Project Longhorn Other - Return of Bond	107 512 -	2,981 1,227 -
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 securities	(670)	(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	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 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	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 in item 1	205
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 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)	(1,142)
8.2	(Payments for exploration & evaluation classified as investing activities) (item 2.1(d))	(17,303)
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
	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 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.

 

END