Acquisition of Texas Oil & Gas Production Assets

88 Energy Limited

15 December 2023

 

This announcement contains inside information

15 December 2023

88 Energy Limited

Acquisition of Additional Texas Oil and Gas Production Assets

Highlights

·    Expanded footprint in Texas Permian Basin with acquisition of further non-operated working interest in leases and wells with conventional onshore production and development opportunities.

·    ~64.4% net working interest (WI) acquired by 88 Energy in 1,262 net acres, located ½ mile south and ¼ mile north of existing Project Longhorn assets (Longhorn) connecting the acreage position.

·    Joint Venture partner and Operator, Lonestar I, LLC (Operator or Lonestar), also acquired a ~21.5% WI in the new assets with remaining WI retained by existing non-operated partners.

·    Purchase price of US$0.35M (net to 88 Energy: US$0.26M) paid in cash by the Joint Venture, Bighorn Energy LLC (Bighorn) which comprises of Longhorn Energy Investments LLC (LEI) a 100% wholly owned subsidiary of 88 Energy (75% ownership) and Lonestar (25% ownership).

·    Attractive low-cost entry of ~US$0.33 per BOE based on the independently certified net 2P reserves position of 0.68 MMBOE^1,2.

·    Nine (9) low-producing existing wells (~26 BOE/day gross) and 10 development opportunities with potential identified in multiple zones and classified as Gross Undeveloped 2P Reserves (1.2 MMBOE^1,2), along with Contingent and Prospective Resources which are yet to be quantified.

·    Coupled with the additional acreage announced in July 2023, Bighorn has reviewed its development opportunities and will now target lower-cost workovers ahead of new drills. Bighorn has approved 5 workovers to be completed in 1H 2024 and upon successful execution are expected to increase production to 180 - 220 BOE gross per day (~75% oil).

·    Once the workovers are completed, Bighorn will consider for approval the 2 new production wells, as previously announced, in 2H 2024, which are expected to increase production by an additional 160-200 BOE gross per day (~75% oil).

·    Upon successful completion of the workovers and new wells across its acreage, together with the existing producing wells, 88 Energy expects Longhorn total gross production to reach approximately 600 - 675 BOE per day (~75% oil) by year end 2024.

·    The new acreage contains 2 injection wells that will be assessed for restoration so that Bighorn has optionality for water disposal, particularly as production increases when new wells come online.

·    Bighorn recently secured a US$5 million line of credit facility to assist in cash flow management associated with the development opportunities.

¹ Refer to page 3 for initial reserves estimates and assumptions.

² Net Revenue Entitlement to 88 Energy.

88 Energy Limited (ASX:88E, AIM:88E, OTC:EEENF) (88 Energy or the Company) is pleased to announce the execution of binding agreements for the acquisition of a new non-operated working interest (WI) (~64% net to 88 Energy) in leases and wells with conventional onshore production and  development assets within the Permian Basin of Texas, U.S.

The new oil and gas production and development assets (Bighorn Phase 3) will form an extended footprint with the initial assets acquired in February 2022 (Bighorn Phase 1) coupled with the new assets acquired in July 2023 (Bighorn Phase 2), all together known as Project Longhorn (Longhorn) as shown in figure 1 below. The new acreage is located approximately ½ mile south of Bighorn Phase 1 and ½ mile north of Bighorn Phase 2. The newly acquired acreage is estimated to contain independently certified net 2P reserves of 0.68 MMBOE^1,2.

Figure 1: Project Longhorn acreage

Importantly and alike to the July 2023 acquisition, all proposed well locations have been classified as low-risk, accessing net Proven reserves totalling 0.56 MMBOE^1,2-, given the production histories from existing wells on the newly acquired leases as well as adjacent leases. The development opportunities should intersect multiple potentially oil-bearing intervals which have been successfully developed in the vicinity of Longhorn and the upside has been identified and classified as Contingent or Prospective Resource and will be quantified.

Purchase price of US$0.35M (net to 88 Energy: US$0.26M) paid in cash by the Joint Venture, Bighorn Energy LLC (Bighorn) which comprises of Longhorn Energy Investments LLC (88E-LEI) a 100% wholly owned subsidiary of 88 Energy (with a 75% ownership interest) and Lonestar I, LLC (Operator or Lonestar) holding a 25% ownership interest.

The acquisition provides 88 Energy with additional flexibility over development capital opportunities including 4 lower-cost workovers (Bighorn CAPEX of ~US$800-950k/each) along with 6 new drill targets to accompany at least 14 new drill targets on existing acreage.

Bighorn has agreed a forward capital development program as part of its 2024 WP&B which includes 5 workovers in 1H 2024 and contingent on successful workovers, 2 new drills in 2H 2024. The 2 new wells (on leases which Longhorn has a ~75% WI), are each anticipated to deliver IP30 of approximately 80-100 BOE per day gross (~75% oil) and cost ~US$1.5 million each, net to 88E-LEI.

Bighorn secured a US$5 million line of credit facility in Q3 2023 to assist in cash flow management associated with the development opportunities. The facility is supported by a local Texas Bank, with interest at Prime and contains no cash lock up, with security over the Longhorn assets. Hedging is required at 50% of production required to secure the drawdown required.  

Longhorn assets in November produced ~370 BOE per day gross (~61% oil) and upon successful completion of the 2024 work program and budget which includes 5 recompletions and contingent 2 new wells planned on the 2023 acquired acreage, 88 Energy anticipates Longhorn total gross production to reach approximately 600 - 675 BOE per day (~75% oil) by year end 2024.

Acquisition details

On 14 December 2023, the Company, via its 75% ownership interest in the Joint Venture subsidiary Bighorn Energy, LLC (Bighorn), acquired an interest in the new leases and wells (Bighorn Phase 3) from Endeavor Energy Resources, L.P., for consideration of US$0.35 million gross to be paid in cash by Bighorn. Bighorn will acquire interests in Bighorn Phase 3 of between 51% - 100% working interest of the leases and wells.

Project Longhorn: Conventional onshore oil & gas production

Project Longhorn assets are in the attractive Texas Permian Basin and following the acquisition, cover approximately 2,625 net acres (of which 1,262 acres relates to the newly acquired leases).  The combined portfolio of assets consists of 18 leases (5 newly acquired) with 49 producing wells (9 within newly acquired leases) and associated infrastructure. Lonestar I, LLC will continue to have a working interest in the assets, and through an affiliate will continue as Operator for the existing and new leases and wells, with the remaining working interests retained by existing non-operated partners.

New acreage production

The existing production wells in the newly acquired acreage have been in operation for several years.  Production from the newly acquired leases in CY2022 totalled approximately 6,200 BOE gross, which had an estimated attributable net profit before tax for the project of ~$0.2 million (unaudited).  Current average production is approximately 26 BOE per day gross (88 Energy's net WI: ~17 BOE per day), of which approximately 75% is oil.

Gross (100%) and Net Entitlement Reserves to 88 Energy (~64.4% net working or net revenue interest ~45%) have been independently assessed by PJG Petroleum Engineers LLC as of 30 September 2023 as follows:

Table 1: Project Longhorn - Bighorn Phase 3 - Reserves (MMBOE)

GROSS RESERVES			NET 88 ENERGY REVENUE ENTITLEMENT
1P	2P	3P	1P	2P	3P
1.00	1.20	1.49	0.57	0.68	0.84

Further ASX Listing Rule 5.31 Information (Notes to Reserves) related to these Reserves is provided in Appendix 1.

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.

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: + 61 8 9268 2829
Cavendish Capital Markets Limited	Tel: [phone]
Derrick Lee	Tel: [phone]
Pearl Kellie	Tel: [phone]

Glossary  Bbl = barrels Bcf = billion cubic feet Bcfg = billion cubic feet of gas Boe = barrels of oil equivalent Bopd = barrels of oil per day Btu = British Thermal Units mcfg = thousand cubic of gas mmcfg = million cubic feet of gas mcfgpd = thousand cubic feet of gas per day mmcf = million cubic feet

Mbo/Mbbl = thousand barrels of oil MMbo/MMbbl = million barrels of oil Mboe = thousand barrels of oil equivalent MMboe = million barrels of oil equivalent Mcf = thousand cubic feet MMcf = million cubic feet mmbtu = million British Thermal Units psi = pounds per square inch UoM = unit of measure IP30 = Average production rate over the first 30 days of production

Appendix 1 - ASX Listing Rule 5.31 Information (Notes to Reserves)

Reserve Evaluation; Project Longhorn -Bighorn Phase 3 Leases

Highlights:

·    PJG Petroleum Engineers LLC (PJG) has prepared the reserve estimates and a forecast of prices and costs evaluation of the oil and gas properties of Project Longhorn - Bighorn Phase 3 leases (New Leases). The effective date of the reserve estimates and cash flow forecasts presented in this release is 30 September 2023.

·    The PJG reserve evaluation has been prepared for 88 Energy in accordance with reserves definitions, standards and procedures contained in the Society of Petroleum Engineers' Petroleum Resources Management System (SPE-PRMS) and reported in the most specific resource class in which the prospective resource can be classified under 2018 SPE-PRMS. The reserves presented in the PJG report are based on forecast prices and costs. Economic Limit Tests (ELTs) used to estimate Reserves shown above were carried out assuming a constant WTI crude oil price of US$75/bbl and a constant US$3.50/mmbtu for the NYMEX gas price. All oil prices used in the evaluation have been adjusted from the reference price for quality and transportation, which is -$0.71/bbl based on historical averages. Gas prices account for NGL's in the gas and have been adjusted for heating value by a factor of 1.30 mbtu/cf based on historical averages. As a result, the net oil and gas prices used in this report are US$74.29/bbl and US$3.13/mcf respectively.

·    The Proved reserves (1P) net of royalties is 0.42 million bbl of oil and 0.76 bcf of gas, or 0.57 million BOE, net to 88 Energy.

·    The Proved plus Probable reserves (2P) net of royalties are 0.50 million bbl of oil and 0.90 bcf of gas, or 0.68 million BOE, net to 88 Energy.

·    The Proved plus Probable plus Possible reserves (3P) net of royalties are 0.61 million bbl of oil and 1.12 bcf of gas, or 0.84 million BOE.

Background

88 Energy, via its wholly owned subsidiary, Longhorn Energy Investments LLC, has a 75% ownership interest in Bighorn energy, LLC (Bighorn) and Lonestar I, LLC has a 25% ownership interest in Bighorn, acquired the new leases from Endeavor Energy Resources, L.P. on 14 December 2023.  The leases comprise approximately 1,683 Bighorn net acres across 5 leases with 9 producing wells and associated infrastructure.

Table 2: Developed Reserves of Acquisition

RESERVES		GROSS			NET ENTITLEMENT
	UoM	1P	2P	3P	1P	2P	3P
OIL	MMBO	0.02	0.03	0.04	0.01	0.01	0.01
GAS	BCF	0.02	0.03	0.05	0.01	0.01	0.02
TOTAL reserves	MMBOE	0.03	0.04	0.05	0.01	0.01	0.02

Table 3: Undeveloped Reserves of Acquisition

RESERVES		GROSS			NET ENTITLEMENT
	UoM	1P	2P	3P	1P	2P	3P
OIL	MMBO	0.71	0.85	1.05	0.41	0.49	0.60
GAS	BCF	1.30	1.56	1.93	0.75	0.89	1.10
TOTAL reserves	MMBOE	0.97	1.16	1.44	0.56	0.67	0.82

Table 4: Total Reserves of Acquisition

RESERVES		GROSS			NET ENTITLEMENT
	UoM	1P	2P	3P	1P	2P	3P
OIL	MMBO	0.74	0.88	1.10	0.42	0.50	0.61
GAS	BCF	1.32	1.59	1.98	0.76	0.90	1.12
TOTAL reserves	MMBOE	1.00	1.20	1.49	0.57	0.68	0.84

The subsequent sections detail the field and reserves/ resources information for compliance with ASX listing rules pertaining to the first announcement of material oil and gas projects.

Assumptions and Notes

a)    The reserves information in this document is effective as of 30 September 2023  (Listing Rule (LR) 5.25.1).

b)    The reserves information in this document has been estimated and is classified in accordance with SPE‐PRMS (Society of Petroleum Engineers ‐ Petroleum Resources Management System) (LR 5.25.2).

c)    The reserves information in this document is reported according to the Company's economic interest in each of the reserves net of royalties (LR 5.25.5).

d)    The reserves information in this document has been estimated and prepared using the deterministic method (LR 5.25.6).

e)    The reserves information in this document has been estimated using a 5:1 BOE conversion ratio for gas to oil; 5:1 conversion ratio is based on an energy equivalency conversion method and does not represent value equivalency (LR 5.25.7).

f)     The reserves information in this document has been estimated on the basis that products are sold on the spot market with delivery at the sales point on the production facilities (LR 5.26.5).

g)    The method of aggregation used in calculating estimated reserves was the arithmetic summation by category of reserves. As a result of the arithmetic aggregation of the field totals, the aggregate 1P may be a conservative estimate and the aggregate 3P may be an optimistic estimate due to the portfolio effects of arithmetic summation (LR 5.26.7 & 5.26.8)

h)    Project Longhorn - Bighorn Phase 3 reserves are located in the Permian Basin, Texas, USA.

ASX LR 5.31 Reserves - Project Longhorn - Bighorn Phase 3 Leases

Project Longhorn - Bighorn Phase 3 Leases
LR 5.31.1 - Material economic assumptions used to calculate the  estimates of petroleum reserves	Oil and gas prices - Oil prices used in this report were kept constant at US$75/bbl to end of field life for WTI crude oil.  This was then adjusted to account for transportation and quality differences based on historical actual prices achieved, which averaged a $0.71/bbl deduction. Natural gas prices used in this report were kept constant at US$3.50/mmbtu for the NYMEX benchmark to the end of field life. Gas prices account for NGL's in the gas and have been adjusted for heating value by a factor of 1.30 mbtu/cf based on historical averages. Consequently, the net gas price used in this report is US$3.13/mcf. Capex - gross capital costs were estimated by the Operator covering drilling and completion, recompletion and abandonment costs considered necessary to recover  the reserves. Capital costs were considered reasonable by PJG, which cost between US$0.8 million and US$2.0 million depending on the type of activity performed. Opex - gross operating costs were based on historical lease operating statements. These forecasts were reasonable by PJG. Discount rate - pre-tax discount rate of 10%
LR 5.31.2 Operator or non-operator interests	Longhorn Energy Investments LLC, a wholly owned subsidiary of 88 Energy Limited, is a non-operator of Project Longhorn and has an average 64.4% working interest across the newly acquired leases, based on area. Table 5 shows lease working interests for the new acreage - Bighorn Phase 3 leases.
LR 5.31.3 Permits or Licenses	The reported reserves relate to the acquisition of 5 leases located in the Permian Basin, Texas, USA. All leases are Held by Production, have no expiry date and no drilling obligations.
LR 5.31.4 Description of:
·      Basis for confirming commercial producibility and booking reserves.	Economic Limit Tests were performed and project NPVs calculated to satisfy the commerciality requirements of the PRMS. PJG carried out these analyses for all wells - current and proposed, based on pricing noted above under LR 5.31.1, Operator provided third party gas plant and oil purchaser statements, Operator provided current royalty rates and all applicable State of Texas oil and gas taxation roles applicable to the specific areas of operations. Future capital requirements and actual historical operating costs were obtained from the Operator's projections and were accepted as reasonable. The commercial producibility of undeveloped reserves is based on stabilised production rates from existing wells and production analogues from the same formations.
·      Analytical procedures used to estimate the petroleum reserves	PJG has relied on Decline Curve Analysis techniques for this evaluation. Production decline analysis was performed using all available production/well test data to estimate a range (Low, Best and High Cases) of production forecasts, which were used as the basis for estimating reserves. An uncertainty range in both the decline rate and the exponent factor of the hyperbolic decline fit was applied to forecast different decline trends attributable to uncertainty in reservoir performance, and to estimate the oil production volumes for the 1P, 2P and 3P reserves categories. These reserves were sense checked against volumetric reserve calculations based on log derived parameters.  Production records were obtained from the Texas Railroad Commission (TRRC) on a lease basis, or when applicable, by combining Operator identified API Number well data historical records, to serve as the basis of the production volumes in our decline curve analysis. This data matched Operator provided data.
·      Proposed extraction method and any specialised processing required following extraction required	All current and proposed wells will utilize sucker rod pumping systems to artificially lift the oil to surface. The reservoirs are largely depletion / solution gas drive with some reservoirs having water aquifer support.
LR 5.31.5 - Estimated quantities to  be recovered	See Tables 2-4 inclusive at the start of Appendix 1.
LR 5.31.6 - Undeveloped petroleum reserves; a brief statement regarding:- ·    Status of the project ·    When development is anticipated ·    Marketing arrangements ·    Access to transportation infrastructure ·    Environmental approvals required	All undeveloped reserves are all located within 1320 ft (40 acres spacing) of existing production; hence development of these reserves simply requires a completed well and tie back to existing production. Two new wells are budgeted to be drilled and completed in 2024. The eight remaining development activities are planned for the 2024-2026 period. All existing marketing arrangements, transportation infrastructure and approvals are planned and budgeted to be utilized.
LR 5.31.7 - Unconventional petroleum resources	Not applicable.
LR 5.32 - Project estimates that have materially changed from when the estimates were previously reported	Not applicable; this report constitutes first time reporting for Project Longhorn - Bighorn Phase 3 leases.

Definitions

·    Reserves are those quantities of petroleum that are anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria, based on the development project(s) applied: discovered, recoverable, commercial and remaining (as of the evaluation date).

·    1P is defined as Proven reserves. 2P is defined as Proven plus Probable reserves. 3P is defined as Proven plus Probable plus Possible reserves.

·    1P or Proven Reserves are those quantities of petroleum that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable from a given date forward from known reservoirs and under defined economic conditions, operating methods, and government regulations. This is typically considered to have more than a 90% likelihood of occurring.

·    Probable Reserves are those additional reserves that analysis of geoscience and engineering data indicates are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. This is typically considered to have approximately a 50% likelihood of occurring.

·    Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. This is typically considered to have approximately a 10% likelihood of occurring.

·    Developed reserves are expected to be recoverable from existing wells and facilities. Undeveloped reserves will be recovered through future investments (e.g. through installation of compression, new wells into different but known reservoirs, or infill wells that will increase recovery). Total reserves are the sum of developed and undeveloped reserves at a given level of certainty.

·    Contingent Resources (2C) are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable owing to one or more contingencies.

·    Prospective Resources are those quantities of petroleum that are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.

Qualified petroleum reserves and resources evaluator statement

The petroleum reserves and resources information in this announcement are based on, and fairly represents, information and supporting documentation prepared by Paul J Griffith. Mr. Griffith has over 35 years of experience in senior technical positions in reservoir, production, and field engineering. He is a registered Professional Engineer in the State of Texas (Credential ID 68149), United States of America, his Firm PJG Petroleum Engineers, LLC is registered to provide Petroleum Engineering services by the State of Texas Board of Professional Engineers under Firm #F-23307.  Mr Griffith is a Lifetime Member of the Society of Petroleum Engineers. Mr Griffith is not an employee of 88 Energy or any of its subsidiaries and has consented in writing to the inclusion of the petroleum reserves and resources information in this announcement in the form and context in which it appears.

Table 5: Working Interest

Lease	Bighorn Energy WI	88 Energy WI	LEASE NRI	88 Energy Revenue Interest
L2-1	100%	75%	85%	64%
L2-2	71%	53%	49%	26%
L2-3	98%	73%	73%	54%
L2-4 *	75%	56%	59%	33%
L2-5	51%	38%	85%	32%
Area Weighted Average	86%	64%	70%	45%

*Working interest in well.

 

END