Vintage Energy Announces Financial Report

Source: www.gulfoilandgas.com 3/4/2021, Location: Not categorized

The Directors of Vintage Energy Limited present their Report together with the financial statements for the half-year ended 31 December 2020.

The directors of the Company in office during or since the end of the period are:
Mr. Reg Nelson (Chairman)
Mr. Neil Gibbins (Managing Director)
Mr. Ian Howarth (Non-executive Director)
Mr. Nick Smart (Non-executive Director)
Mr. Ian Northcott resigned as the alternate Director to Mr. Ian Howarth on 11 August 2020.

All directors held office during and since the end of the period, unless otherwise stated.

Principal activities
The principal activities of the Company include securing exploration projects, undertaking exploration, appraisal and evaluation for oil and gas resources, and seeking to realise value from oil and gas exploration interests.

Results for the period
The Company reported a loss for the half-year ended 31 December 2020 of $1,039,236 (31 December 2019 $1,155,045).

The Company has continued to execute its exploration program as detailed in the Company’s IPO prospectus and described in the review of operations detailed below. Movements in the Statement of Financial Position are a reflection of the program’s execution.

Corporate
Escrow Shares
On 11 September 2020, 45,363,232 unlisted Founders’ shares that were held in escrow for 24 months following the Company’s initial public offering in 2018 were released from restriction and converted to unrestricted ordinary shares in the Company.

Capital raising
On 17 September 2020, Vintage announced a capital raise via share placement to institutional and sophisticated/professional investors and an entitlement offer to existing shareholders at an issue price of $0.06 per share. The Company received gross proceeds of $15.2 million from the capital raise by December 2020.

Subsequent events
On 1 March 2021, the Class B performance rights issued to executives pursuant to the Company’s Employee Share Plan and rights issued to Managing Director Mr. Neil Gibbins, approved at the 17 December 2018 Annual General Meeting, were converted to ordinary shares in the Company, based on performance conditions being met.

On 1 March 2021, the Class C performance rights issued to executives pursuant to the Company’s Employee Share Plan and rights issued to Managing Director Mr. Neil Gibbins, approved at the 17 December 2018 Annual General Meeting, lapsed due to performance conditions not being met. Refer note 15(c) for conditions relating to these rights.

Cooper/Eromanga Basins, Queensland
ATP 2021 (VINTAGE 50% AND OPERATOR, METGASCO LTD 25%, BRIDGEPORT (COOPER BASIN) PTY LTD 25%)
The highly successful flow test program for Val-1 ST1 delivered a stabilised gas flow rate of 4.3 MMscfd through a 36/64“choke at a flowing well-head pressure (“FWHP”) of 942 psi over a two-day period. Transient tests were also undertaken with rates recorded between 3.7 MMscfd (through a 24/64” choke at 1,676 psi FWHP) and 7.5 MMscfd (through a 32/64” choke at 1,593 psi FWHP). The program was carried out safely and as planned.

Strong rates were achieved during all flow periods and quick pressure build-ups were observed during all shut-in periods, with pressure levels quickly approaching around 3,000 psi. All flow rates were restricted through varying choke sizes to ensure proppant was not returned from the formation into the well bore, therefore avoiding any reduction in the effectiveness of the stimulation process.

During the flow testing of the well, the following activities were undertaken:
• Production Logging Tool run, which determined that gas was being contributed by each of the stimulated zones
• Shut-ins, which observed the pressure response of the reservoir, with pressure readings reaching 2,932 psi at the end of the recording period and continuing to build
• Flow testing, with transient tests undertaken under various choke sizes of 24/64”, 32/64” and 40/64” over three equal periods of six hours
• Gas samples taken, with the composition in line with typical Cooper Basin Patchawarra wells

A development concept for the Vali Field has been completed and estimates a field life of around 20 years, with up to nine fracture stimulated vertical wells to target production from reservoirs in the Patchawarra Formation and the Tirrawarra Sandstone.

A type of well production profile has been developed based on the flow test at Vali-1 ST1, and with reference to the decline characteristics of nearby fields. The current base case development concept for the Vali Field is for initial raw gas production of approximately 5 MMscfd (gross) per well for total production of around 5 Bcf per well (on an average well outcome basis). Surface facilities at Vali will be kept to a minimum through the construction of a main manifold that will gather gas from producing wells and deliver it into existing pipelines, with a separator and metering system to also be installed.

Some of the development concept work has been carried out by GPA Engineering (“GPA”). GPA has consulted with Santos, as operator of the SACB JV infrastructure, and confirmed the preferred connection point for a Vali Field pipeline is the Santos operated Beckler Field. Gas will then be transported through the existing pipeline system for processing at Moomba once infrastructure access and gas sales agreements are executed. It is envisaged that connection from Vali would be via multiple composite pipelines, the number and size of which will be defined in the detailed engineering phase of work.

The capital cost associated with the pipeline connection is based on Front End Engineering Design (“FEED”) work carried out by GPA. FEED for Vali-1 ST1 connection to the Beckler Field (which is connected to the Dullingari facilities and ultimately Moomba) was completed by GPA. The main objective of FEED was to complete the necessary engineering to identify long lead items and refine the cost estimate for a final investment decision, which will then initiate the procurement stage. Operating costs are expected to be low, with the facilities to be as simple and intervention free as possible.

To maximize value from the Vali gas field, through increased production and resultant cash flow, further wells are planned. To this end, potential locations for further drilling in the field have been identified, with an amended FY21 budget including Vali-2 and long lead items for Vali-3 now approved by the joint venture. Completion of the Vali-1 ST1 well is necessary ahead of connecting the well into the Moomba gathering system.

Production tubing was run into the Vali-1 ST1 hole with isolation packers successfully set on two occasions, however, pressure testing via the production tubing in the well bore indicated a leaking seal assembly on the completion. A black viscous substance was noted as a film on the first packer assembly after its retrieval from the borehole. The substance may be precipitating on the casing and causing the packer leaks under pressure testing. Samples have now been sent for analysis to determine chemical composition and a plan will be developed to remove the material on returning to site to finalise the completion. Although frustrating, deferral of the completion is not critical to the timeline for first production.

Cultural heritage and environmental surveys were recently completed in ATP 2021 for the surface facility, flowline and possible future well locations. The process was completed in a timely manner with the Wongkumara People, Erias and GPA/FYFE and we appreciate and thank all parties for their effort to complete this work in a timely manner.

First reserves for the Vali Field were certified by ERC Equipoise Pte Ltd (“ERCE”), which completed a rigorous and independent review of the Vali gas discovery and subsequent flow results. The Vali-1 ST1 well discovered stacked gas pay in the Nappamerri, Toolachee, Patchawarra and Tirrawarra Formations, however, the scope of the ERCE reserves certification was for the Patchawarra Formation reservoir only. The reserves booking is the first for Vintage and supports commercialisation of the Vali gas field with its planned connection into the Moomba gathering system.

In its report, ERCE estimated gross 1P reserves for the Patchawarra Formation of 12.3 billion standard cubic feet (“Bcf”), 2P of 30.3 Bcf and 3P of 78.9 Bcf which equates to 1P of 13.4 petajoules (“PJ”), 2P of 33.2 PJ and 3P of 86.6 PJ.

Vintage is hopeful that gas produced from the Vali Field will be much greater than the 2P figure estimated by ERCE, with upside to potentially come from stacked reservoirs, including the shallower Nappamerri Group and Toolachee Formation. Vintage has brought this project from farm-in, to discovery, to successful testing and now to reserves booking in just over one year, which is an outstanding achievement for a company at such an early stage since listing.

Notes to the table above:
1. Reserves estimates reported here are ERCE estimates, effective 1 December 2020.
2. Vintage is not aware of any new data or information that materially affects the Reserves above and considers that all material assumptions and technical parameters continue to apply and have not materially changed.
3. Reserves estimates have been made and classified in accordance with the Society of Petroleum Engineers (“SPE”) Petroleum Resources Management System (“PRMS”).
4. Net Reserves attributable to Vintage represent the fraction of Gross Reserves allocated to Vintage, based on its 50% interest in ATP 2021.
5. Allowance for Fuel and Flare has been made.
6. Conversion of Bcf to PJ has been estimated based on gas sampled and measured from Vali-1 ST1.
7. ERCE Reserves presented in the tables are the totals for all 20 Patchawarra reservoir intervals.

Resource Evaluator
ERCE is an independent consultancy specializing in petroleum reservoir evaluation. Except for the provision of professional services on a fee basis, ERCE has no commercial arrangement with any other person or company involved in the interests that are the subject of this Contingent Resources evaluation.

The work has been supervised by Mr Adam Becis, Principal Reservoir Engineer of ERCE’s Asia Pacific office who has over 14 years of experience. He is a member of the Society of Petroleum Engineers and a member of the Society of Petroleum Evaluation Engineers.

Otway Basin, South Australia/Victoria
PEL 155 (VINTAGE 50%, OTWAY ENERGY PTY LTD 50%)
The joint venture signed a non-binding Memorandum of Understanding (“MOU”) with Supagas Pty Ltd (“Supagas”), an Australian based distributor of gases for domestic, industrial, medical and other applications.

Under the MOU, Supagas will fund work associated with the preliminary design and costing of facilities for processing Nangwarry carbon dioxide (“CO2”), which will allow for the production and delivery of food grade CO2. In return, the joint venture will provide Supagas the opportunity to submit a formal proposal to develop and/or purchase gas from the Nangwarry reservoir. The MOU signed with Supagas supports the development, production and purchase of Nangwarry CO2, and is a reflection of the confidence the joint venture has in the Nangwarry discovery.

The first Otway Basin recoverable CO2 booking for the Nangwarry-1 discovery was estimated by employing a method consistent with the June 2018 Society of Engineers Petroleum Resources Management System (“PRMS”) methodology. Under PRMS, volumes of non-hydrocarbon by-products cannot be included in any Reserves or Resources classification. ERC Equipoise Pte Ltd (“ERCE”) has assessed the sales gas volumes attributable to the Nangwarry-1 discovery using a methodology consistent with that prescribed by the PRMS. ERCE independently assessed a Best Case of 25.1 Bcf gross recoverable CO2 in the top Pretty Hill Sandstone of the Nangwarry CO2 discovery (12.6 Bcf net to Vintage). This compares extremely well with other commercial Otway Basin CO2 fields such as Caroline (~15 Bcf), which was in production for approximately 50 years, and Boggy Creek (~14 Bcf).

The Nangwarry-1 well has a high-quality CO2 gas column of approximately 90 metres, based on sampling and pressure data, with a further 45 metres subject to confirmation by testing. Laboratory analyses indicate that around 90% of the gas content is CO2, with the residual being methane. This is an excellent outcome as the methane can be separated from the CO2 and used to power the facility that would process the gas to food grade quality CO2.

Notes to the table above:
1. Recoverable CO2 and Contingent Resource estimates reported here are ERCE estimates.
2. Gross Contingent Resources represent a 100% total of estimated recoverable hydrocarbon volumes.
3. Resource estimates have been made and classified in accordance with the PRMS guidelines and methodology.
4. Recoverable CO2 estimates have been made and classified using a method consistent with the PRMS guidelines and methodology.
5. Net recoverable CO2 attributable to Vintage represents the fraction of gross recoverable CO2 allocated to Vintage, based on its 50% interest in PEL 155.
6. Volumes reported here are “unrisked” in the sense that no adjustment has been made for the risk that the project may not be developed in the form envisaged or may not go ahead at all (i.e., no Chance of Development factor has been applied).
7. Chance of Development for the recoverable CO2 has been estimated to be 75% by Vintage and agreed by ERCE. This is based on the ability to establish a skid mounted processing facility at the well-head, adequate road access for trucks to transport the CO2 to market, similar reservoirs developed nearby such as Caroline-1, and high downstream demand for food grade CO2.
8. Hydrocarbon Contingent Resources have been sub-classified as “Development Unclarified” under the PRMS by ERCE and are assigned as Consumed in Operations, that is used as fuel for the CO2 plant. The key contingencies are a final investment decision on development, committing to a CO2 sales agreement, any other necessary commercial arrangements, and obtaining the usual regulatory approvals for production.
9. Recoverable CO2 volumes shown have had shrinkage applied to account for methane and include only CO2 gas.
10. Recoverable CO2 and Contingent Resources presented in the tables are the probabilistic totals for the Pretty Hill Sandstone reservoir interval.
11. Probabilistic totals have been estimated using the Monte Carlo method.

The testing of the Nangwarry-1 well is expected to take place around mid-March 2021 (barring any COVID-19 restrictions), with all long lead items ordered and contractors confirmed for that time. The testing will use a rig from Superior Energy in Victoria and testing equipment from Firetail that was brought into the Otway Basin for a recent testing program in Victoria. The testing operations are planned to be conducted over a three-to-four-week period.

The testing program will include a short flow test of the mid-Pretty Hill Sandstone, which will be followed by the shallower zone and flow test of individual sands in the interpreted CO2 column at the top of the Pretty Hill Sandstone. The test will be completed once a desired stabilised flow rate and volumetric estimate of the recoverable CO2 is obtained.

Perth Basin, Western Australia
CERVANTES STRUCTURE (WITHIN L14) (VINTAGE EARNING 30%, METGASCO EARNING 30% AND RCMA AUSTRALIA PTY LTD 40%)
Preparations for the drilling of Cervantes-1 continued through the period. A further survey was recommended by environmental authorities and completed in September 2020 and EPA approval is expected in H1 2021. The Cervantes Joint Venture signed a non-binding Letter of Intent (“LOI”) with Refine Energy Pty Ltd (“Refine”) to use Refine Rig-2 for the drilling of the Cervantes exploration prospect, planned for the first half of 2021. On 22 October 2020, RCMA entered into a two-well farm-out and tolling agreement with Refine. Under the arrangement Refine will drill two wells in Q1 2021 in the L14 Licence area utilising Refine Rig-2 approximately 3 km from the proposed Cervantes-1 surface location. Under the terms of the Cervantes Joint Venture LOI with Refine, the Mob/Demob is minimal due to the rig proximity to Cervantes, reducing the overall estimated drilling cost. Subject to EPA and regulatory approvals and acceptable performance of Refine Rig 2 during the RCMA/Refine two-well drilling program, the Cervantes prospect is planned to be drilled as soon as possible following this program, allowing optimal rig and crew efficiency. A full rig contract agreement with Refine is being finalized.

Galilee Basin, Queensland
ATPS 743, 744 AND 1015 “DEEPS” (VINTAGE 30%, COMET RIDGE LTD 70% AND OPERATOR)
Onsite operations at the Albany gas field have been suspended by the operator.

Subsequent events
COOPER/EROMANGA BASINS - ATP 2021
The Joint Venture has elected to prioritise work to assess the resource upside of the Vali gas field and surrounding area, which will include the drilling of Vali-2 (and Odin-1) ahead of the purchase of flowline infrastructure. Vali-2 will address the interpreted Toolachee Formation gas accumulation in the Vali structure, which, if successful, would provide additional reserves to those recently certified in the Patchawarra Formation. As well as this, desktop studies will address further prospectivity and potential upside in the region. The benefits behind this timing are fourfold. It is expected to deliver an appropriately sized flowline over the long-term, allow for the potential development of a production hub, provide gas marketing advantages, and give greater exposure to a rising gas price. The planned timing for drilling Vali-2 will be around April/May 2021, pending rig availability and other approvals. A rig contract has been signed with Schlumberger to use SLR Rig-184 for the drilling of Vali-2 and Odin-1, with an option to drill a further ATP 2021 well. It is expected that the above approach will be favourable from a value perspective, however, it will likely result in the deferral of first gas production to late this year or possibly early next year.

However, by focusing on assessing the resource upside ahead of first gas, there is the potential to optimise the value of these assets, with the following benefits expected to be realised:
1. Appropriately sized flowline – by better defining field volumes through drilling, the flowline will be developed with adequate capacity for future production over the long-term.
2. Development of a production hub – further technical and operational work will better define resource upside in the area surrounding the Vali Field. This could add significant value to the Vali Field as a potential production hub for the area.
3. Gas marketing advantages – the Joint Venture will be in a stronger position to market larger volumes of gas, with the potential for improved terms and pricing.
4. Exposure to rising gas prices – gas prices are increasing, with forecasters and market commentators expecting this trend to continue.

Although the procurement of flowline equipment will now follow the prioritised evaluation program, other non-equipment related activities, such as Moomba access agreements, route surveying, environmental approvals, and government approvals, are continuing as planned to ensure an efficient installation of the flowline once equipment selection has been approved.

As previously advised, during the completion works at Vali-1 ST1 the packer seal failed to hold pressure against the casing during completion, with the likely cause being the presence of a black grease-like substance in the bottom third of the wellbore. Chemical analysis of the substance showed that it is consistent with a lubricant used at surface and not a product of the reservoir. This is a positive finding and is supported by the fact that all downhole equipment previously used in flowback and well testing operations were retrieved in clean condition.

Apart from hindering the sealing mechanism, the deposit is of no concern for production operations. The plan moving forward will be to mechanically scrape the casing over the intervals in which the packers will be set against the casing, which is a relatively common operation in the industry.

The ACCC recently granted interim authorization for the Joint Venture to enter into joint marketing arrangements. The interim authorisation allows the parties to begin jointly negotiating and entering into conditional long-term gas agreements with customers for the supply of gas from the Vali field.

COOPER/EROMANGA BASINS - PRL 211 (VINTAGE 42.5% AND OPERATORSHIP, METGASCO LTD 21.25%, BRIDGEPORT (COOPER BASIN) PTY LTD 21.25% AND STUART PETROLEUM PTY LTD (WHOLLY OWNED BY SENEX ENERGY LTD) 15%)
The Joint Venture has accelerated the drilling of the Odin prospect, with the Odin-1 well expected to be drilled around May/June 2021 (following Vali-2), pending rig availability and other approvals. The Odin structure is up-dip of Strathmount-1, which intersected interpreted Permian gas pay, and is a Permian four-way dip closure that plunges to the north-east into the Nappamerri Trough.

The Odin structure has been de-risked by the success at Vali-1 ST1 and has the potential for gas in the Toolachee Formation (~8 metres of structural relief over nearly 5.2 km2), with a 40% chance of success (“COS”) and high chance of development, and the Patchawarra Formation (~15 metres of structural relief over nearly 2.5 km2), with a COS of 32% and high chance of development. The Odin Structure has a Gross Prospective Resource of: 1U low estimate of 3.6 Bcf (1.6 Bcf net), 2U best estimate of 12.6 Bcf (5.7 Bcf net), 3U high estimate of 42.6 Bcf (19.0 Bcf net) (refer ASX release dated 22 November 2019).

OTWAY BASIN (PEL 155)
The procurement of long lead items has been completed, with the Superior Energy rig expected at site on 10 March 2021. The testing program will include a short test of the mid-Pretty Hill Sandstone to verify upside potential we believe exists in this section of the column, which will be followed by a move into the shallower zone and a flow test of individual sands in the interpreted CO2 column at the top of the Pretty Hill Sandstone.

The successful completion of the production test will be a key milestone on the path to first production of food grade CO2. If successful, the test will confirm volumes of saleable CO2 and allow the Joint Venture to consider appropriate infrastructure/debt funding options for the infrastructure required to deliver food grade CO2, with the co-produced methane used to run the production plant. Supagas has already commissioned preliminary design work for a skid mounted CO2 plant, in line with the MOU signed in 2020.


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