88 Energy has provided 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 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 transferred remaining outstanding 2023 cash call amount due of US$1.75 million and remains committed to the Hickory-1 flow test authorised funding expenditure (AFE).
Managing Director, Ashley Gilbert, commented on Project Phoenix:
'In what has proven to be a pivotal quarter for 88 Energy and its shareholders, we achieved the successful flow of oil to surface, for the first time, from the previously untested USFS reservoir and also subsequent to quarter end from the shallower SMD-B reservoir, both at our Hickory-1 discovery well. This represents a tremendous achievement that adds immediate value to Project Phoenix and unlocks multiple pathways for future commercialisation.
With flow testing operations complete, we will now transition to post well analysis and are moving to secure further Contingent Resources at Project Phoenix.
We expect to commence a formal farm-out process for Project Phoenix following completion of the Hickory-1 post flow test analysis, with the aim of attracting a strategic partner for the next stage of development and commercialisation.'
Namibia PEL 93 (20% WI)
- Transfer of 20% working interest in Petroleum Exploration Licence 93 (PEL 93) complete, being the first stage of a three-stage farm-in agreement following approval by the Namibian Ministry of Mines and Energy.
- PEL 93 includes an extensive lead portfolio with ten significant independent structural closures identified from a range of geophysical and geochemical techniques and potential for more leads to be identified as dataset is expanded.
- Seismic acquisition is planned for mid-2024 with potential initial exploration well targeting the Damara play as early as H2 CY2025.
Project Leonis (100% WI)
- Maiden prospective resource estimate for Upper Schrader Bluff (USB) reservoir expected H1 2024.
- Farm-out process commenced with multiple parties engaged and reviewing data room materials, ahead of potential drilling of a new well in 2025/2026.
Project Longhorn (~64% WI)
- Two of the planned five workovers scheduled to be in completed in 1H 2024 are underway and are currently projected to be delivered under budget.
- Q1 2024 production steadily averaged 328 BOE per day gross (~62% oil).
- Company received cash flow distribution of A$0.7M in March 2024.
- The Company also reduced it's working interest in 9 leases during the quarter by an average of a ~7% reduction in net WI's across these leases. Consideration for these leases totalled A$0.3M.
Corporate
- Cash balance of A$17.5 million and no debt (as at 31 March 2024), ~20% of Hickory-1 flow test payments have been made, with the remainder expected to be paid in Q2 2024.
- Net cash outflows in relation to operating expenses for Q1 2024 totalling A$0.77M as compared to A$1.44M in Q4 2023.
- Cost reduction initiatives commenced in the quarter targeting a reduction in salary and overhead costs. Further business optimisation activities underway, aimed at preserving and enhancing value for shareholders and advancement of key projects.
Project Phoenix (~75% WI)
Project Phoenix is focused on oil-bearing conventional reservoirs identified during the drilling and logging of Icewine-1 and Hickory-1 and adjacent offset drilling and testing. Project Phoenix is strategically located on the Dalton Highway with the Trans-Alaskan Pipeline System running through the acreage.
The Hickory-1 discovery well was previously drilled in February 2023. All American Oilfield's upgraded Rig-111 was subsequently secured in September 2023 to conduct the flow test. During the March 2024 quarter, ice road and pad construction works were completed and the rig was subsequently mobilised. Flow test operations commenced in March 2024.
The testing operations focussed on the two primary targets, the SFS and SMD reservoirs. Of the SFS series of reservoirs, the Upper SFS reservoir was targeted to be flow tested as it has not been previously tested, whereas the Lower SFS has previously been flow tested and producibility of that reservoir confirmed on adjacent acreage. The Upper SFS was followed by a targeted testing of the SMD-B reservoir. Each zone was independently isolated, stimulated and flowed to surface using nitrogen lift to assist in an efficient clean-up of the well.
Upper SFS flow test results
A 20ft perforated interval in the Upper SFS reservoir was stimulated via a single fracture stage of 241,611 lbs proppant volume. The well was cleaned-up and flowed for 111 hours in total, of which 88 hours was under natural flow back and 23.5 hours utilising nitrogen lift.
The USFS test produced at a peak flow rate of over ~70 bopd. Oil cuts increased throughout the flow back period as the well cleaned up, reaching a maximum of 15% oil cut at the end of the flow test program. The Company expects that oil rates and cut would have likely increased further should the test period have been extended. The well produced at an average oil flow rate of approximately 42 bopd during the natural flow back period (with established production rates occurring over an ~11 hour test period, accumulating ~19bbls of oil. An additional ~6bbls of oil was recovered outside of the established production period), with instantaneous rates ranging from approximately 10 - 77 bopd with average rates increasing through the test period. Importantly, the USFS zone flowed oil to surface under natural flow, with flow back from other reservoirs in adjacent offset wells only producing under nitrogen lift. A total of 3,960bbls of fluid was injected into the reservoir and 2,882bbls of water was recovered during the flow back period, most of which was injection fluid. Total flow rates (inclusive of recovery of frac fluid) averaged ~600 bbl/d over the duration of the flow back.
Multiple oil samples were recovered with measured oil gravities of between 39.9 to 41.4 API (representing a light crude oil).
Additionally, some natural gas liquids ("NGLs") were produced but not measured, as was anticipated in the planning phase. The presence of NGLs was demonstrated by samples from the flare line and by visible black smoke in the flare. Historically, NGL prices on the North Slope of Alaska have been similar or slightly below light oil prices and are therefore considered highly valuable. Further work is required to quantify the exact volume of NGLs, which 88 Energy intends to include as part of a maiden certified Contingent Resource assessment at Project Phoenix for the SFS reservoirs.
For full details in relation to the Upper SFS test results please refer to the ASX announcement dated 2 April 2024.
SMD-B flow test results (subsequent to quarter end)
A 20ft perforated interval in the SMD-B reservoir was stimulated via a single fracture stage comprising 226,967 lbs of proppant volume. The well was cleaned-up and flowed for 84 hours in total, utilising nitrogen lift throughout the entire test period. The average fluid flow rate over the duration of the flow back period was approximately 445 bbls/d, with choke sizes ranging from 8/64ths to 33/64ths.
The SMD-B test produced at a peak estimated flow rate of ~50 bopd. Oil cuts varied throughout the flow back period, reaching a maximum of 10% oil cut. The well produced at an average oil cut of 4% following initial oil to surface, with instantaneous rates observed during the 16-hour period varying as the well continued to clean up. Total stimulation load water was not recovered and water salinity measurements indicated we were recovering load water at the conclusion of the test. Unlike flow tests on adjacent acreage where multiple gas lift mandrels and valves were used in completions designs, and nitrogen was unloaded in the tubing in stages up the well bore, Hickory-1 utilised a single gas lift mandrel where nitrogen was introduced via one valve at the deepest section. This is viewed as positive indication for future potential rates and performance.
Multiple oil samples were recovered, with measured oil gravities of between 38.5 to 39.5 API, representing a light crude oil.
Importantly, the SMD-B zone flowed oil to surface with little to no measurable gas, representing a low GoR production rate. Pressurised oil samples collected during both the USFS and SMD tests will be transported to laboratories for further analysis.
The SMD-B flow test was concluded with sufficient information for the next steps, and the data recorded will assist 88E in optimisation and design processes in the next phase of advancement of Project Phoenix.
For full details in relation to the SMD-B test results please refer to the ASX announcement dated 15 April 2024.
Namibia PEL 93 (20% WI)
In February 2024, the Company announced the successful 20% WI transfer by Monitor Exploration Limited (Monitor) to 88 Energy in relation to PEL 93 located in the Owambo Basin, Namibia following receipt approval from the Ministry of Mines and Energy.
The Company, via its wholly-owned Namibian subsidiary, previously executed a three-stage farm-in agreement in November 2023 for up to a 45% non-operated working interest in onshore Petroleum Exploration Licence (PEL 93), which covers 18,500km2 of underexplored ground within the Owambo Basin in Namibia (refer to ASX announcement dated 13 November 2023).
Under the terms of the agreement, 88 Energy may earn up to a 45% working interest by funding its share of agreed costs under the 2023-2024 approved work program and budget as defined in the Farm-In Agreement (2024 Work Program) and any future work program budgets yet to be agreed. The maximum total investment by the Company is anticipated to be US$18.7 million.
The current and potential future PEL 93 Joint Venture partners and working interests are as follows:
Namibia has been identified as one of the last remaining under-explored onshore frontier basins and one of the World's most prospective new exploration zones. PEL 93 is more than 10 times larger than 88 Energy's Alaskan portfolio and more than 70 times larger than Project Phoenix.
Recent drilling results on nearby acreage has highlighted the potential of a new and underexplored conventional oil and gas play in the Damara Fold belt, referred to as the Damara Play. Historical assessment utilised a combination of techniques and interpretation of legacy data to identify the Owambo Basin, and specifically blocks 1717 and 1817, as having significant exploration potential.
Monitor has utilised a range of geophysical and geochemical techniques to assess and validate the significant potential of the acreage since award of PEL 93 in 2018. It has identified ten (10) independent structural closures from airborne geophysical methods and partly verified these using existing 2D seismic coverage. Further, ethane concentration measured in soil samples over interpreted structural leads validates the existence of an active petroleum system, with passive seismic anomalies also aligning closely to both interpreted structural leads and measured alkane molecules (c1-c5) concentrations in soil.
The forward work-program will start with a low impact ~200 line-kilometre 2D seismic program focusing on confirming the structural closures of the 10 independent leads identified. The 2D seismic program will be conducted in mid-2024 following a period of planning, public consultation, updating of environmental compliance requirements and relevant approvals. Results from the 2D seismic program will then be incorporated into existing historical exploration data over the acreage, with results used to identify possible exploration drilling locations.
Project Longhorn (~65% WI)
In December 2023, the Joint Venture (Bighorn JV), Bighorn Energy LLC (Bighorn) which comprises Longhorn Energy Investments LLC (LEI) a 100% wholly owned subsidiary of 88 Energy with 75% ownership and Lonestar I, LLC (Lonestar or Operator) with remaining 25% ownership, finalised its 2024 work program and budget. The Bighorn JV agreed to a development program that included 5 workovers in 1H 2024 and 2 new wells in 2H 2024, contingent on successful workovers.
During the quarter, the Bighorn JV commenced two of the planned five workovers with assessment of production occuring during April 2024.
Q1 2024 production averaged a fairly steady 328 BOE per day gross (~62% oil) which was slightly below the budgeted volume of 346 BOE per day gross (65% oil) due to January winter storms and the Company received a cash flow distribution of A$0.7M in March 2024.
The Bighorn JV executed a ~10% sell-down (gross, ~7% net to 88 Energy) of the 2023 acquired acreage, in order to re-disk and accelerate development opportunities. The transaction realised acquisition payments of ~A$0.3M and the non-operated partners will contribute their share of the capital development costs coupled with a 25% carry of their ownership share on the five 2024 WP&B agreed workovers.
Information required by ASX Listing Rule 5.4.3
Source: 88 Energy
