Member Info for Sailplane

Underlying Project Parameters

These NPV10 barrel values are calculated over a multi-phase, life-of-field life cycle using the following baseline economic boundaries: 

Oil Price Assumption: A flat long-term Brent price of US$73.63 to US$77.00 per barrel.

Life of Field Capex: Estimated at US$7.50 per barrel.

Life of Field Opex: Estimated at US$20.10 per barrel.

Production Breakeven: Highly resilient at approximately US$24.00 per barrel

AI responses may include mistakes. So double check and DYOR

Q:what is the current in the ground value per barrel calculated for npv10 over the life of the [PL001] project.

AI take on that:

A:The "in-the-ground" value per barrel calculated via NPV10 for a commercial discovery in this specific basin ranges between US$8.79

 and US$15.98 per barrel, depending on whether corporate taxes are factored in.

Because PL001 is an exploration licence, it does not yet have an independent project-specific NPV10. Instead, the industry uses the exact economics calculated in the April 2026 Netherland, Sewell & Associates (NSAI) Independent Report for the adjacent, geologically identical Sea Lion development as the benchmark.

1. The Post-Tax, Post-Royalty Value: US$8.79 per Barrel

This represents the clean, fully clear net value of a barrel to a joint venture partner over the life of the project: 

The Metrics: For the Proved + Probable (2P) sanctioned case, the 35% working interest yields 109.84 million barrels of reserves.

The Value: This volume generates a net NPV10 of US$965.8million.

Calculation: $965,800,000 / 109,840,000bbls = US$8.79 per barrel.

This incorporates all capital costs (Capex), operating expenses (Opex), state royalties, and Falkland Islands corporate income taxes.

The 109.84 million barrels benchmark used for the NPV10 economic calculations does not physically sit inside the PL001 block; rather, it belongs to the adjacent Sea Lion field (PL032). However, this figure is the exact economic blueprint, operational template, and commercial justification for how findings inside PL001 will be monetized. 

The 109.84 million barrels tie directly to the imminent findings and prospects in PL001 through geological replication, infrastructure access, and fast-track scaling:

Direct Analogy to Tyche and Dinlas

The 109.84 million barrel reserve is composed of Lower Cretaceous sand fans trapped stratigraphically against the basin margin. 

The PL001 Link: According to JHI - Eco (Atlantic) Oil & Gas Plc, the high-graded Tyche and Dinlas prospects inside PL001 sit within the exact same stratigraphic interval, age, and geological character as the Sea Lion accumulation.

Scale Comparison: While the Sea Lion Phase 1 & 2 baseline proves up 109.84 million barrels net (from a ~314 million barrel gross pool), Tyche and Dinlas are each estimated at 400 million barrels gross of recoverable oil. Success at either prospect immediately matches or exceeds the entire calibrated scale of the Sea Lion project.

AI responses may include mistakes. So double check and DYOR

The AI take on this:

What the ConocoPhillips Deal Means

The project developer, Glenfarne Group, has pivoted to an all-of-the-above approach. By signing up all four producers (ConocoPhillips, ExxonMobil, Hilcorp, and Pantheon) for Phase 1, they are creating a blended gas pool. 

Instead of relying only on Pantheon or Point Thomson, the project will now mix Pantheon’s ultra-low CO 2  gas with the higher-CO 2 volumes from the majors. This blending lowers the overall CO 2 percentage to an acceptable level for the pipeline, drastically reducing—or completely eliminating—the need for a massive, expensive processing plant at the start of Phase 1. 

Your premise was entirely correct: Pantheon's low-CO 2  gas was chemically necessary. The new milestone simply means the project isn't choosing between the majors and Pantheon; it is using Pantheon's clean gas to unlock the majors' massive volumes.

AI sometimes makes mistakes, so DYOR. Anyone got corroborative evidence on this gas blending idea?

AI response:

There is a distinct difference in how the UK government approaches oil and gas exploration in the 

Falkland Islands versus the UK North Sea . This has led to accusations of hypocrisy from political opponents and industry groups.

Key Differences in Policy and Regulation

Jurisdictional Independence: Because the Falkland Islands is a self-governing British Overseas Territory, the Falkland Islands Government (FIG) has its own national system for petroleum licensing and regulation.

The "Miliband Ban": Energy Secretary Ed Miliband has implemented a ban on new exploration licences in the UK North Sea as part of a managed transition to renewable energy. However, the UK Foreign Office has stated that this ban does not extend to the Falkland Islands, asserting that decisions there are a matter for the FIG and private companies.

Regulatory Standards: While the jurisdictions are separate, the FIG regulates its offshore extraction using UK North Sea standards, which are among the highest safety and environmental benchmarks globally.

Economic Strategy:

North Sea: The UK government argues that new North Sea licences won't improve energy security or lower bills because oil is sold on international markets.

Falkland Islands: The FIG views hydrocarbons as a "political and community priority" essential for achieving economic independence. The UK government acknowledges that Falklands production could contribute to "domestic security of supply" via international markets. 

In summary, the UK government technically "allows" the Falklands to proceed by respecting their right to self-determination, even as it blocks similar new activity in its own domestic waters. 

AI responses may include mistakes. So DYOR

Q: after an expensive shop for licenses adjacent to kodiak would the likes of repsol and shell really be still interested in farming into pantheon's kodiak

AI responce:

A: Major energy companies, including those that participated in the March 2026 lease sale, remain in "advanced discussions" with Pantheon Resources regarding a potential farm-in for the Kodiak field. 

The expensive lease acquisitions by Repsol and Shell adjacent to Kodiak may actually increase the likelihood of a farm-in for several strategic reasons:

Validation of Geology: High-value bids for adjacent tracts serve as a major external validation of the geological play Pantheon has discovered.

Infrastructure Synergy: Repsol and Shell's new federal leases in the NPR-A and state lands effectively "bracket" Pantheon's holding. A partnership would allow for coordinated regional development, potentially sharing the cost of pipelines to the Trans-Alaska Pipeline System (TAPS).

Access to Existing Data: While Repsol/Shell now own the land next door, they do not own the proprietary 3D seismic data and well results from Pantheon's Theta West-1 discovery. Farming in is the most direct way to access this critical technical data.

Strategic Consolidation: Pantheon currently holds a 100% working interest in Kodiak, an asset with over 1.2 billion barrels of recoverable liquids. For a major like Repsol or Shell, farming into an existing giant discovery is often less risky than starting grassroots exploration on their new, untested blocks.

AI sometimes makes mistakes, so DYOR.

AI's thoughts:

Pantheon is in a relatively strong negotiating position because its Kodiak field is a certified 1.2 billion-barrel resource, making it one of the largest onshore discoveries globally in recent years. 

Pantheon Resources

Kodiak Strategy: Analysts suggest Pantheon may seek a higher carry for Kodiak due to its "cornerstone" status.

Ahpun Strategy: Because Ahpun is closer to development, Pantheon might prioritize a partner that provides infrastructure funding rather than just drilling carries. 

Pantheon is currently in active data room discussions with multiple majors to finalize these exact terms by the end of 2026. 

To maximize the value of the Kodiak field for a farm-in deal, Pantheon Resources is executing a multi-stage appraisal strategy focused on proving the field's massive 1.2 billion-barrel potential is commercially viable. 

1. High-Resolution Seismic Reprocessing 

In early 2026, Pantheon began reprocessing 3D seismic data over the northwest section of the Kodiak project.

The Goal: Use modern computing to gain "improved granularity" of the rock structures.

Value Impact: This allows for precise selection of future well locations and provides higher-quality data for potential partners conducting due diligence in the data room. 

2. Drilling the Theta West-2 Appraisal Well

The primary physical milestone is the Theta West-2 well, currently planned for the winter of 2026/27.

The Goal: Target the shallower, "updip" portion of the reservoir where management expects the highest quality rock (greater porosity and permeability).

Value Impact: This well is designed to convert "contingent resource" estimates into proven commercial reserves, which is the critical trigger for a major farm-in partner to commit significant capital. 

3. Comprehensive Reservoir Characterization

Future appraisal wells like Theta West-2 are intended to include full core samples, wireline logs, and flow tests.

The Goal: Address technical "contingencies" regarding how easily the oil will flow to the surface.

Value Impact: Proving that the reservoir has "conventional" characteristics (porosity above 12% and permeability above 0.1 mD) would significantly increase the asset's intrinsic value and Pantheon's negotiating leverage. 

4. Strategic Integration with Alaska LNG

Pantheon is positioning Kodiak's 5.4 trillion cubic feet (Tcf) of associated natural gas as a strategic asset for the proposed Alaska LNG project.

Value Impact: Linking the oil development to a potential gas sales agreement provides an additional revenue stream that makes the project more attractive to supermajors looking for long-term gas security. 

By completing these steps, Pantheon aims to achieve their stated goal of demonstrating a market value of $5–$10 per barrel of recoverable resource by 2028.

AI sometimes makes mistakes, so DYOR.

The map on this link:

https://www.akbizmag.com/industry/government/17-5m-from-state-north-slope-lease-sale/

shows where Repsol [who apparently had a revenue of some $61.8billion in 2024] bought the licences to the blocks on the North West of PANRs Kodiak area in November 2025. [mentioned in paragraph 6 - saying they expanded their position with forty-five leases to the south of the Kuparuk River Unit.]

For those not familiar with the location of Kodiak, it includes the light green area a little above the largest purple block on this map, plus Talitha.

Comparisons of the Theta West and Talitha A wells and areas.

The oil-bearing rocks at the Theta West project are significantly superior to those at Talitha #A, primarily because Theta West is located in a more "proximal" (closer to the sediment source) and structurally higher position. 

Reservoir Comparison

Permeability and Flow Potential: Analysis suggests a potential 10x improvement in permeability (specifically the

perm rate) at the top of the Lower Basin Floor Fan (LBFF) at Theta West compared to the distal sections seen at Talitha.

Structural Advantage: Theta West #1 is approximately 1,500 ft structurally higher and "up-dip" from Talitha #A. This shallower depth of burial generally preserves better reservoir quality by reducing compaction.

Rock Volume: Theta West revealed over 1,460 ft of continuous oil-bearing cuttings, confirming massive oil saturation. 

Improvement to the North West

The reservoir quality improves significantly as the formations move north west of Theta West for the following reasons: 

Proximal Deposition: Seismic mapping shows the Basin Floor Fan continuing up-dip for several miles to the north west, moving from distal "basin plain" rocks to superior "channel facies".

Facies Transition: Shifting from the thin, interbedded "tiger stripes" (sands and shales) seen in more distal locations toward thicker, cleaner channel sands increases the net-to-gross sand ratio and overall porosity.

Improvement to the North West of Theta West

Proximal Deposition: As the fan moves north-west (further up-dip), the sand quality is anticipated to improve from distal basin plain to higher-quality channel facies.

Shallowing Structure: Seismic data suggests the field structure increases in quality as it becomes shallower to the north-west, which is generally associated with higher permeability.

Additional Potential: Recent seismic analysis indicates the reservoir extends roughly 12 miles northwest of Theta West, with anticipated improvements in reservoir quality in these shallowest areas.

And, guess what...Pantheon Resources currently holds licenses extending approximately 12 miles northwest of the Theta West #1 discovery well. 

So... wouldn't you expect Repsol - just might have more than a fleeting interest in what happens at Kodiak?

Some of the above obtained by repeat 'deep and wide' questioning of AI.

And AI sometimes makes mistakes, so double check & DYOR.

Q: What resources attributed to pl001 in falklands and how much does this mean for ECO oil & gas

A: The PL001 licence in the North Falkland Basin is attributed with a "Best Estimate" of 3.1 billion barrels of unrisked prospective recoverable resources. These resources are spread across more than 50 identified prospects and leads within the 1,126 

 block. 

Resource Breakdown

Total Prospective Resources: 3.1 billion barrels (Best Estimate), with an aggregate upside exceeding 10 billion barrels.

Key High-Graded Prospects:

Tyche: Estimated 400 million barrels of recoverable oil.

Dinlas: Estimated 400 million barrels of recoverable oil.

Geological Context: Several prospects, including Tyche and Dinlas, are considered geologically analogous to the adjacent Sea Lion field, which has over 700 million barrels of recoverable resources. 

Impact for Eco (Atlantic) Oil & Gas

For Eco (Atlantic) Oil & Gas, the acquisition of JHI Associates (expected to close in Q3 2026) is a "transformational milestone" that shifts the company from pure exploration toward development-led growth. 

Significant Equity Stake: Eco will gain a 35% working interest in PL001 through its 100% ownership of JHI.

Fully Funded Exploration: A farm-in agreement with Navitas Petroleum (which will hold a 65% interest) provides JHI—and thus Eco—with a fully funded carry loan for an exploration well and a potential appraisal well, worth up to $14 million net.

Infrastructure Synergies: PL001 is immediately adjacent to the Sea Lion development (also operated by Navitas), which reached a Final Investment Decision (FID) in late 2025 and targets first oil in 2028. Proximity to Sea Lion's future production platform allows for potential tie-backs, reducing development risks and costs for PL001.

Strategic Alignment: The deal strengthens Eco's partnership with Navitas, a development-focused operator, across their broader portfolio, which includes assets in Guyana and South Africa.

AI responses may include mistakes. So double check and DYOR

AI:

In the Falkland Islands, current activity on PL001 is focused on high-end technical preparation rather than new physical acquisition. The two legacy exploration wells on the block were not drilled with 3D seismic; they were based on older, regional 2D data. 

Seismic Activity on PL001 (Current Status)

As of early 2026, the current focus is on seismic reprocessing and integration rather than a new "shoot". 

Navitas Petroleum

Proprietary 3D Coverage: The entire 1,126 

 area of PL001 is already covered by a high-quality, proprietary 3D seismic survey acquired by Argos Resources in 2011.

Advanced Reprocessing: The current operators, Navitas Petroleum and Eco (Atlantic) Oil & Gas, are leveraging this existing 3D data to identify more than 50 prospects, including the high-priority Tyche and Dinlas targets.

Both prospects are estimated to hold 400 million barrels each. If successful, they would likely be developed as subsea tie-backs to the Sea Lion FPSO, significantly increasing the project's overall value. 

Integration with Sea Lion: Engineers are currently integrating this 3D data with results from the adjacent Sea Lion field to de-risk drilling targets for the upcoming exploration phase. 

Legacy Wells and 3D Seismic

The two primary legacy wells on the block—14/24-1 (Braela)

 and 14/13-1 (Minke), drilled by International Petroleum Corporation (IPC) and LASMO in 1998—were located using 2D seismic data. 

Drilled on 2D: These wells were part of the initial 1998 drilling campaign which relied on regional 2D grids and sparse geological models.

Subsequent 3D Results: After the 2011 3D seismic survey was processed, it was revealed that these legacy wells did not optimally test the structural and stratigraphic targets now visible on the 3D data.

Improved Success Rates: The industry shift toward 3D has significantly increased the "geological chance of success" for the next round of drilling by better mapping the complex fan systems and fault traps.

The Timeline: While Sea Lion development work starts in 2026, the first exploration well on PL001 is most likely to be spudded in 2027, ahead of "first oil" from Sea Lion in early 2028. 

Expansion of the Aberdeen Support Hub:

To manage both the Sea Lion build-out and the PL001 exploration campaign, Navitas is opening a dedicated operations office in Aberdeen in early 2026. This office will lead the procurement for "long-lead items" (like wellheads and casing) needed for the upcoming PL001 drilling.

AI responses may include mistakes. So double check and DYOR.

map showing PL001 & Sealion: https://www.oedigital.com/news/534270-navitas-eyes-more-north-falklands-exploration-acreage-after-sea-lion-fid

Q. Referring to the 16feb2026 pantheon resources RNS and pertaining to the Dubhe1 well, with its recent flowback profile, what is your interpretation of both the principal, and any more subtle meanings that are within the phrase: As we shift our focus toward engineering execution.

A. AI Overview

Based on the 16 Feb 2026 update, the phrase "As we shift our focus toward engineering execution" highlights a transition from initial, high-cost, and challenging flowback testing at Dubhe-1 to a structured, technical plan aimed at proving commerciality

. It indicates a pivot from pure exploration to optimized development of the Ahpun asset.

Principal Interpretation:

Operational Pivot: The focus shifts from simply testing to engineering solutions (e.g., using ESPs) to overcome early cleaning-up challenges and establish commercial flow rates.

Cost Management: It signifies a shift away from high-cost ($150,000/day) winter operations toward more efficient, planned, or potential spring/summer operations, aiming to optimize financial efficiency.

Data Utilization: It emphasizes applying data from the initial, difficult flowback—which saw significant water, modest oil, and high gas—to refine future extraction techniques.

Subtle Meanings & Context:

Risk Management: It masks a "pivot" away from potentially disappointing or underwhelming early results (relative to pre-drill hype) by emphasizing long-term "engineering" rather than immediate, high-volume production.

Resource Management: It indicates that the company is pausing to avoid burning through cash during the winter, allowing for reservoir pressure build-up and a more precise, less wasteful approach later.

Preparation for Partnership: It signals a professionalization of the project to make it more appealing for farm-out discussions, suggesting that technical, engineered data will be prioritized to secure a partner for development. 

In essence, it is a statement of "strategic pause and reassessment," moving from "test-at-all-costs" to "engineered, economic development," reflecting a more cautious, data-driven approach after early results.

AI responses may include mistakes.

So DYOR.

Q. Elaboration on the pore mechanism at Dube 1

Thinking

Searching

A. The pore mechanism at

Dubhe 1 is defined by the interaction between the reservoir's "tight" rock matrix and the massive volume of stimulation fluids injected during its 25-stage hydraulic fracture.

The following pore-level factors explain the current flow behavior and the expected benefits of the "soak" period:

1. The "Water Block" and Relative Permeability

Pore Saturation: During stimulation, approximately 200,000 barrels of water were forced into the reservoir. In tight sandstones like the SMD-B, the pore throats are extremely small (often micrometer-scale), creating high capillary forces that "trap" this water near the wellbore.

Permeability Choke: Because the pores are currently saturated with water, the relative permeability—the ease with which a specific fluid moves—heavily favors water and gas over oil. Oil molecules, being larger and more viscous, are physically blocked by the "water bank" occupying the primary flow channels.

2. Capillary Imbibition (The "Soak" Mechanism)

The "soak" period is designed to use natural capillary forces to rearrange fluids at the pore level:

Spontaneous Imbibition: In a water-wet or mixed-wet reservoir, the rock matrix naturally "wants" to pull in water. During the shut-in, capillary pressure draws the injected frac water from the large fractures into the smaller, deeper "micro-pores" of the rock.

Oil Displacement: As the rock sucks in the water, it simultaneously "kicks" the oil out of those tiny pores and into the larger fracture network. This process essentially swaps the positions of the fluids, clearing the main "highways" (fractures) for oil flow when the well is reopened.

3. Gas Mobility vs. Oil Viscosity

Gas Bypass: Gas has much lower viscosity and can navigate through water-saturated pores far more easily than oil. This explains why 20 million cubic feet of gas has already been produced while oil remains "modest".

Pressure Stabilization: Shutting the well in allows the reservoir pressure to equalize. This prevents the "flash" of solution gas that occurs during high-drawdown flow testing, which can create a "gas lock" in the pores that hinders oil movement.

AI responses may include mistakes.

...So DYOR

Q. Why was the Pantheon Dubhe 1 well, with ~50% frac recovery, flowing gas but so far only minor amounts of oil. Also detail the way in which Dubhe 1 might evolve following the shut in pressure testing and 'soak' period before returning to flow testing in the spring.

A. AI Overview [AI responses may include mistakes....So DYOR]

The Pantheon Resources Dubhe-1 well in Alaska, having recovered approximately 50% of the 200,000+ barrels of stimulation fluid (frac load) and flowing primarily gas with minor oil, is currently undergoing a planned pause and "soak" period. The decision to shut in was driven by high daily winter operating costs (~$150,000/day) and the need for further cleanup to determine commercial potential. 

Why Dubhe-1 Produced Gas/Minor Oil with 50% Frac Recovery:

Incomplete Fluid Recovery & Blockage: The well had only recovered about 50% of the injected water/fluids at the time of the pause. In unconventional, low-permeability reservoirs (like the SMD-B), the remaining "trapped" stimulation fluid often clogs the formation, preventing oil from reaching the wellbore, while allowing more mobile gas to flow.

High Water Cut Masking Oil: In similar, complex reservoirs, the "thick straw" (main hydraulic fractures) must be cleaned of water before consistent, higher-volume oil production begins.

Analogue Comparison (Alkaid-2): Pantheon's closest analog, the Alkaid-2 well, first saw meaningful oil production only after roughly 50% of the injected water was recovered, suggesting the well is at the turning point, not at the end, of the testing process.

Multiple Stage Challenges: As a 25-stage, multi-stage, longer horizontal lateral (5,200 ft), different stages may be cleaning up at different times, causing a staggered or slower transition from water/gas to oil compared to single-stage, shorter wells. 

Evolution of Dubhe-1 During the 'Soak' and Future Flow Testing: The well is currently in a "soak" phase, meaning it is shut in to allow for pressure buildup and diagnostic evaluation, which helps determine the commercial potential of the reservoir. 

Pressure Equalization: The shut-in allows the pressure within the fractures to equalize, potentially clearing the "water block" and allowing formation oil to flow into the fractures.

Fluid Redistribution: The "soak" period may allow remaining water to move away from the immediate vicinity of the fractures, improving oil mobility.

Reduced Operational Costs: Pausing allows for the avoidance of high winter operating costs while still, in effect, performing diagnostics.

Resumption in Spring: Upon resuming flow testing in the spring, the goal is for the well to show significantly higher, more stable oil flow rates as the reservoir has "cleaned up" further during the down period, aiming to move the well toward commercial viability. 

Based on the 50% recovery milestone, the team is looking for a shift in oil production, similar to the behavior observed in earlier, smaller-scale tests....

The SMD-B drill logs, shown and described, with a lot more detail than they appear to give us on recent wells:

https://www.youtube.com/watch?v=hbnmarRCUcY&t=2896s

And an excellent Video Presentation - a 3D view of the various oil reservoirs, on the Pantheon acreage, detailing from the Kuparuk all the way up to the SMD.

https://www.youtube.com/watch?v=hbnmarRCUcY&t=3462s

M-kid: 'The curious thing here is Tom Reynolds, our non-exec buyer, has just become CEO of Prospex Energy by 1st Feb 2026.'

and of Prospex energy, AI says:

Prospex Energy PLC (Stock Ticker: PXEN)

Prospex Energy PLC is an AIM-quoted investment company focused on European gas and power projects.

Core Assets: The company holds working interests in three key natural gas projects:

Selva Malvezzi (Italy): A 37% interest in this gas field, which has been producing since July 2023.

Viura (Spain): A 7.2% interest in this producing gas concession in Northern Spain.

El Romeral (Spain): A 100% interest in a gas-to-power project in Southern Spain.

Strategy: The firm focuses on late-stage, drill-ready exploration or reworking existing fields to bring them to production quickly.

SuperK 10:58

I think the recovery of significant oil is taking longer than they had hoped – hence running into the bad winter weather - but it looks like it’s running the Alkaid2 SMD-B test playbook, where little oil was seen until about 56% frac load recovery when the pressure in the well bore’s frac fluid would have dropped below the pressure in the reservoir, allowing the oil to suddenly started to flow from the rocks.

If you want to quickly get a grip on what Pantheon has in its Ahpun and Kodiak fields, take a look at a presentation they did for the Talitha A well.

https://www.youtube.com/watch?v=hbnmarRCUcY&t=657s

Talitha A drills through the overlap of Kodiak with Ahpun and so they present and discuss the drill logs showing oil, water, side core sample points, porosity and permeability. An excellent presentation – understandable, yet in more detail than they appear present now days.

This Aug 2021 presentation is an excellent one to watch if you want to know more about what oil is 'down there' on the Pantheon's patch.

It's available at

https://www.youtube.com/watch?v=hbnmarRCUcY&t=657s

at this 657s timed start point there's good explanation given for the diagrams of the log analysis performed at the Talitha A well, (which is about 7miles west of Duhbe1) and includes some SMD analysis.

They discuss the logs and linking them with sidewall core results, tell you what the logs mean. And it covers oil finds from the deep Kuparuk, the Basin floor fans [lower and upper], the Slope Fans and the SMD - A, B & C. The logs show the relationship of sand, shale, oil, water, porosity and permiability in these reservoirs.

So, the Talitha A well is at the overlap of the Ahpun and Kodiak fields, so here you get to see the reservoirs in both.

At other points in this presentation, there are some memorable comments:

at time 21:18, Michael Smith – inventor of Volatiles Analysis (VAS)

“Every cutting we analysed contained oil for 3,700 feet – this is a quite unusual occurrence and really speaks to the great strength of the petroleum system here where this well is drilled. This is really a world class petroleum system.”

at 38:35, Dr Ed Duncan, Geoscience consultant to Pantheon

“What we found is truly amazing – the Theta West Fan – while we thought it was going to be good – it’s spectacular.”

at 1:41:42, Roger Young of eSeis

“I’ve never seen anything like it. To be able to say the words – Half a Mile of Oil – that’s ridiculous, but it’s true. It’s awesome. I’ve never seen anything like it. It’s very, very exciting stuff.”

And the geology that gave rise to those exciting words - it is still down there, on the Pantheon leases.

IMHO. Always DYOR

Dubhe-1 has, so far, only recovered ~50% of the stimulation fluids, but clean ups from Hickory1 and Alkaid2 tests of the SMD-B, in their vertical well sections, appear to have both had to progress beyond 50% frac load recovery for significant flows of oil to materialise from this reservoir.

PREVIOUSLY successful flow tests of the SMD-B reservoir have been from:

Alkaid2 located ~9miles north of Dubhe1

Hickory1 ~5miles south of Dubhe1 and drilled by 88E Ltd - there was a Pantheon's Talitha #A well dataswap for 88 Energy's Hickory #1's

ALKAID 2:

REF: the recent PANR Dec2025 webinar - it was explained and presented on a graph (page11), that this Alkaid2 single frac test of the SMD-B only flowed oil above 50% frac recovery and from the graph, at ~56% frac recovery the oil flow ramped up suddenly to an initial peak of ~11% oil cut concurrent with ~942bbls of frac load. So calculating as ~103.6bopd and with further recovery, the percentage oil cut had an increasing trend.

REF: RNS 19 October 2023 Alkaid-2 Re-entry Update

During the flow test, after recovery of approximately 60% of the frac fluids, the oil rate (separator liquids) ranged from more than 100 barrels of oil per day ("bopd") to 30 bopd (averaging 45 bopd over the 5 days during which oil was recovered). Water cuts were 90% initially, but declined over time as a larger share of the frac fluids was recovered. As highlighted before the operation, the flow rates themselves were not expected to be material because the objective was to limit drawdown in the initial flow back. However, the actual flow rates were substantially better than prognosed, given the conservative approach to production in order to limit gas flashing in the reservoir and ensure the best quality PVT samples, which bodes well for future SMD development in the Ahpun Field.

HICKORY 1 – REF: 88E RNS 15 April 2024 HICKORY-1 FLOW TEST - SECOND LIGHT OIL DISCOVERY

SMD-B: with a peak flow rate ~50 bopd of light oil (measuring approx. 39-degree API oil gravity, under nitrogen lift)... A 20ft perforated interval in the SMD-B reservoir was stimulated via a single fracture stage...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.... Some 70% of stimulation fluid had been recovered at the conclusion of the test ... Oil cut would be expected to improve once stimulation fluid was fully recovered.

The Hickory1 well has its SMD-B situated in a down dip location relative to that at Dubhe1 and so one would expect higher porosity and permeability at Dubhe1.

IMHO DYOR

Q. Using the analogy of thin and thick straws for the rock matrix and fraced volume around an oil well describe why oil production may not occur until after 50% or more of the frac load is recovered

A. In the context of hydraulic fracturing, the relationship between the rock matrix and the fractured volume can be explained using the analogy of thin and thick straws. This analogy illustrates why oil production often remains minimal until a significant portion (often 50% or more) of the fracturing fluid is recovered. 

1. The Thick Straw (Frac Volume)

Capacity: The "thick straw" represents the large, man-made fractures created during the fracking process.

Initial State: During the fracking operation, this thick straw is completely filled with high-pressure fracturing fluid (water, chemicals, and proppants).

Flow Behavior: Because this straw is "thick" (high conductivity), fluid flows through it easily. However, because it is currently saturated with water-based frac load, there is no room for oil to enter the wellbore through this channel. 

2. The Thin Straws (Rock Matrix)

Capacity: The "thin straws" represent the microscopic pores and tiny natural cracks within the tight rock matrix where the oil is actually trapped.

Initial State: Before fracking, these thin straws are filled with oil. However, they are so narrow (low permeability) that the oil cannot move out on its own.

Water Blockage: When the thick straw is pressurized with frac fluid, some of that water is forced into the ends of the thin straws. This creates a water block or "capillary trap" that physically pins the oil deeper into the rock matrix. 

3. Why Production is Delayed (The 50% Threshold)

Path of Least Resistance: When the well is opened for production, the pump or natural pressure first pulls from the "thick straw" because it offers the least resistance. This results in the "flowback" of primarily fracturing fluid.

Clearing the Channel: Oil production cannot begin in earnest until the "thick straw" is sufficiently cleared of water. If the fracture is still half-full of water, the pressure from the thin straws is not enough to push oil through the water-clogged main channel.

Establishing Connectivity: Once roughly 50% or more of the injected fluid is recovered, the water level in the "thick straw" drops enough to create a continuous path for the oil to flow from the rock matrix (the thin straws) into the main fracture and up to the surface. 

During the frac water load recovery phase of an oil well, an extended pause (often called soaking or shutting-in) can offer significant production benefits, particularly in unconventional or tight oil reservoirs. Though immediate flowback is common for cleaning the wellbore, pausing allows for subsurface mechanisms that can improve long-term yields. 

The potential benefits of an extended pause include:

Mitigation of Water Blocking: During fracturing, water can become trapped near the fractures, blocking oil from flowing out. An extended pause allows this trapped water to dissipate deeper into the formation through spontaneous imbibition, effectively "clearing the path" for oil.

Enhanced Initial Flow Rates: Wells that undergo a "soaking" period often show a significant "flush production" spike when finally opened. In some cases, initial production rates have been reported to be up to five times higher than similar wells brought online immediately.

Reduced Water Disposal Costs: Because more fracturing fluid is absorbed into the formation matrix during the pause, the well typically produces less water during the early flowback stage, lowering immediate disposal and handling costs.

Formation Energy Supplementation: Shut-in allows fluid pressure to diffuse more evenly throughout the reservoir. This rebalancing can supplement formation energy, potentially increasing the total area of the reservoir effectively swept for oil.

Optimal Duration: Research suggests that there is a "sweet spot" for shut-in time. Studies on certain tight reservoirs found that 32 to 64 days resulted in the highest economic prospects, while shorter periods (under 8 days) showed no significant benefit. 

As always DYOR.

Receipt of Independent Resource Report - Talitha (Shelf Margin Deltaic)

The directors are pleased to announce that LKA have confirmed a Prospective Resource of 302 Million Barrels of Recoverable Oil for the SMD horizon at Talitha.

Definitions referred to in this announcement for Prospective Resource and Prospective Resource have been prepared under the Society of Petroleum Engineers ("SPE") standards. 

 

Highlights:

⇨ 302 Million Barrels of Oil ("MMBO") Prospective Resource (Recoverable)

⇨ $2.7 billion(1) NPV10 modelled on 91 producing wells, using a long term Brent oil forward curve ranging from $45.84 to $54.89

⇨ $8.92 NPV10 per barrel of oil(2) and an Internal Rate of Return of 79.9%

⇨ Field peak maximum production rate(2) of 90,000 Barrels of oil per day ("BOPD") facility limited

⇨ Average individual producing well EUR (estimated ultimate recovery) of 3.32 MMBO per well(2) for 91 producing wells

⇨ The LKA report confirms that Talitha is an Appraisal project updip from discovered oil

⇨ Located near the Dalton Highway & Trans-Alaska Pipeline (TAPS) allowing a phased development and minimising upfront capex

 

Notes: (1) NPV's are calculated on a pre-tax basis after deduction of a modelled 13.5% royalty rate. (2) Production volumes & EUR's are quoted on gross production numbers (i.e. pre 13.5% royalty)

 

The LKA Prospective Resource estimate only covers 20,600 acres of the reservoir section updip from the oil pay at the Pipeline State #1 discovery well, and not the total resource across the entire structure or project area. The Production Unit at Talitha covers 44,373 acres. The project area was delineated using advanced seismic attribute analysis where LKA reported that "The seismic AVO attributes show likely stratigraphic trapped good reservoir for the Shelf Margin Deltaic to the up-dip direction from well Pipeline State #1".

Bob Rosenthal, Technical Director, commented: "This is another extraordinary result for our Company. The delineation of such a large Prospective Resource in the SMD, immediately updip from discovered oil is very exciting. LKA have detailed an expectation of a high quality reservoir with porosity over 15% and recovery factors of 30%,...