REG - 88 Energy Limited - Quarterly Report and Appendix 5B
18/04/2024 07:00
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RNS Number : 1403L 88 Energy Limited 18 April 2024
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 18,500km(2) 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
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
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 Year to date (3 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 (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 2,874 2,874
Other - Distribution from Project Longhorn 715 715
Other - Return of Bond - -
2.6 Net cash from / (used in) investing activities (415) (415)
3. 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 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 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 Current quarter Previous quarter
at the end of the quarter (as shown in the consolidated statement of cash flows) to the related items in the accounts
$A'000
$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
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 214
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 Director 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
$US'000
$US'000
financing arrangements 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) (768)
8.2 (Payments for exploration & evaluation classified as investing activities) (3,851)
(item 2.1(d))
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
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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.
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