Q&A

1) US listing / Nasdaq / reverse split / dual listing

What is the current status, timeline, and key remaining steps for a US (e.g. Nasdaq) listing, and should shareholders expect a reverse split to meet listing requirements? Will Pantheon maintain a dual listing to protect UK retail holders (ISAs/SIPPs), and what measures will be taken to limit volatility/shorting during any transition?

As advised, Pantheon’s preparations for a potential US listing are on hold after completing the preliminary necessary work. The Company’s strategy was to be sufficiently prepared for a US listing such that, if a window opened, the “flash to bang” time would be short enough to allow capitalize on the opportunity. The Company had undertaken preliminary tasks around potential legal and tax structuring, initial accounting requirements and a framework of controls that would need to be implemented regardless of whether a US listing occurred. The work on these specific US listing activities has been paused.

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2) Funding runway, 12-month needs, cash (net of payables), and financing strategy

What is Pantheon’s current cash/liquidity position (including net of trade payables), burn rate (G&A and operational), and funding runway—specifically, is the Company fully funded to complete Dubhe clean-up/testing through spring 2026 without another raise? What are the expected funding needs over the next 12 months and the preferred mix of debt, farm-out/JV, non-dilutive funding, and equity to bridge the path to First Oil?

The Company disclosed cash on hand of $27.5 million on Dec 22, 2025. Some portion of that is committed to trade payables.. Funding needs depend on the extent of the 2026 work programme including the ultimate costs of evaluating the Dubhe-1 well, seismic reprocessing over potential well locations for a Kodiak appraisal well etc.

Pantheon raised $30 million before costs in September 2025 to add to the liquidity to execute its plans. After the webinar, the 2025 annual results announcement included a statement on the going concern status noting a need for further funding during the second half of the year. Furthermore, the Company raised a further $10 million before costs in January 2026.

Under the current strategy, the funding path to first oil is predicated on maximizing the debt that can be secured against a take or pay contract for gas sales (assuming completion of the Gas Sales Precedent Agreement with 8 Star Alaska to a full Gas Sales Agreement) and plugging any gap with equity. If circumstances result in a change of strategy, the Company will seek to secure funding from a combination of farm-outs and equity issuance that maximize the intrinsic value retained for investors. The Company remains focused on maintaining flexibility in its financing strategy and continues to assess market conditions.

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3) Non-dilutive financing milestone ($100m)

Regarding the revised management incentive milestone for a “Non-Dilutive Financing Award” of at least $100m, how much qualifying non-dilutive funding has been secured to date?

This question relates to remuneration and, more specifically, the conditions attached to a significant proportion of the share option awards granted to Executive Chairman David Hobbs in 2024. To date, no “Non-Dilutive Financing” has been secured and thus no performance based share options have vested.

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4) Dilution, discounted equity raises, capital discipline, and future approach

How does the Board reconcile prior discounted equity issuance and dilution (including Sun Hung Kai / CLN structures) with its “price maker not price taker” messaging and capital discipline, and what concrete commitments can it make to avoid similar dilution/structures going forward?

The Company’s funding strategy is based on seeking to minimize value dilution for existing investors by seeking to retain the maximum proportion of the intrinsic value of the assets. There are three sources of “value dilution”:

1. Time value of money
2. Disposal of working interest
3. Sales of shareholder equity

Each decision on funding is taken with a view to maximizing the retained value while managing the related risks. It is important to recognize that disposal of working interest represents a permanent dilution (investors have no opportunity to reacquire the portion that is sold) whereas sales of shares leave an option for investors to buy back in at a later date to maintain their share of the intrinsic value. Decisions on funding are taken with a view to minimizing delays because each year imposes a cost equivalent to the cost of capital.

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5) Share price fall, PR/RNS quality, and communications consistency

Why have recent RNS announcements and follow-up communications produced severe share price declines, and what specific changes will management make to improve drafting quality, consistency between RNS and interviews/webinars, timing of communications, and the level of operational detail provided to investors?

In providing factual updates in our RNS announcements, the Company seeks to avoid the use of language that could be interpreted as either promotional or unduly pessimistic. Written disclosures are inherently limited in their ability to convey nuance, tone, or context that may be available through verbal communications such as webinars. Any operational detail being shared in a written announcement will necessarily involve simplification and summary in the interests of brevity. In complying with its disclosure obligations under the AIM Rules and UK Market Abuse Regulation, the Company seeks to provide information that is clear, accurate and not misleading.

In future communications, the Company will continue to calibrate RNSs in a way that meets the needs of as many shareholders as possible without compromising the appropriate rules.

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6) “Envelope of expectation” / confidence language / commercial thresholds

Can management define the “envelope of expectation” and the benchmarks behind statements like “confident”—including practical flow-rate ranges and other criteria that would indicate success/commerciality vs underperformance for Dubhe-1?

It is the role of management to avoid overly simplified or artificially precise benchmarks or statements of expectations that lack context or the flexibility to respond to circumstances that could not be foreseen with confidence. For example, the proportion of the frac load expected to be recovered prior to oil breakthrough would have been expressed as an extremely wide range if formal guidance had been issued because there is no deterministic method for predicting the percentage recovery prior to oil breakthrough. Instead, the “envelope of expectation” language conveyed that the information received up to that time did not provide a basis for altering management’s pre-well prognosis for the Dubhe-1 well outcome.

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7) Dubhe-1: timeline, what data comes when, and what “pause/restart” means

What is the realistic timeline and results cadence for Dubhe-1 (what will be announced and when), what does “restart in spring 2026” mean in calendar terms (March/April/etc.), and what are the operational implications/risks of pausing now (including potential setbacks, well integrity concerns, and restart costs)?

At this time, no specific date has been set for re-starting Dubhe-1. Prior to restarting, several work items must be completed to fully meet the overall appraisal objective and ensure lowest cost operations. This includes analysis of the production data gathered, further analysis of data gathered when drilling the well (e.g. core) and sufficient time to complete the pressure build up survey which is ongoing. In addition, numerous cost-saving initiatives are underway involving artificial lift, well operation services and water disposal. These need to be completed and executed prior to any restart operation. When a final decision has been made on the forward programme, it will be communicated.

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8) Winter vs spring/summer operating cost: amounts, drivers, and savings

What is the expected daily cost of testing/operations in spring/summer versus winter (~$150k/day), what drives the winter premium (approximate breakdown), and what are the total savings expected from pausing now versus continuing through winter?

The cost structure of well testing prior to the pause were dominated by artificial lift (i.e. nitrogen injection), well testing equipment and services and produced water transportation and disposal. Each of these was amplified by weather conditions. As part of the work program during the pause period, each of these items is being carefully considered, given we now know the overall production characteristics of the well. The largest areas of costs savings will be associated with artificial lift and water management. For example, nitrogen lifting was chosen initially to manage the risk of sand production which is incompatible with downhole pumps. Given the conditions experienced in December 2025, it was not prudent to intervene in the operations. Given the time to prepare, management expects a major shift in cost structure upon restart.

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9) Representative/stabilized production: when data becomes meaningful

At what point during flowback does production data become representative for decision-making, what indicators distinguish “clean-up noise” from true reservoir performance, and when do you expect to declare a stabilized representative production rate?

There is no definitive time, event or industry standard that would trigger the end of the testing period. The objective is to see a sustained set of stable parameters (e.g. volumes, pressures, and temperatures) indicative of steady state reservoir contribution. This has not been achieved as of yet on Dubhe-1. Upon restarting the well we would continue to observe these trends carefully to understand and extrapolate reservoir deliverability.

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10) Dubhe-1 performance vs expectations/analogues and “how far off are we”

How does Dubhe-1’s performance (oil, gas, water, cleanup progression) compare with pre-drill expectations and analogues (Alkaid-2 / SMD-B), and what explains the gap between expected and observed outcomes to date?

The company is unable to confidently provide benchmarks at this time. Thus far, the well is within the range of pre-drill expectations and local analogues, and thus, no definitive determinations have been made.

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11) Water production: source, trends, handling costs, and implications

What is the expected water-production behaviour for Dubhe-1 (best analogue), is produced water primarily frac fluid vs formation water, has water cut materially improved recently, and are development operating-cost assumptions being updated for water handling/disposal?

This is one of the expected outcomes from Dubhe-1 testing. There are no known analogues for long term production from Pantheon’s asset base. This well will inform development planning in that regard.

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12) Why hasn’t oil flowed “meaningfully” yet, and should oil breakthrough still be?

Why hasn’t Dubhe-1 cut meaningful oil yet, what evidence supports the expectation of oil breakthrough later in cleanup (e.g., the 50–60% recovery analogy), and why will spring operations be different/better?

There is no deterministic model that would reliably predict when meaningful oil breakthrough should be expected. It is normal to rely upon experience and analogues but there is a very limited data set for wells completed in the SMD-B horizon in the Middle Schrader Bluff interval on Alaska’s North Slope. The pause in operations allows analysis and planning for restart of operations and any intervention, such as to run an electric submersible pump, would likely be more cost effective.

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13) Nitrogen/artificial lift: usage, rationale, and implications

Has nitrogen lift been used at Dubhe-1, at what stages and why; how should investors interpret nitrogen/artificial lift regarding reservoir quality and expected future production; and why was nitrogen used on prior tests such as Alkaid SMD-B?

Nitrogen has been used for artificial lift in the well. In early production phases, the production stream is 100% water, and assistance is required to flow to surface in a stable manner. There are many options available for this in industry including downhole pumps. Gas lift using Nitrogen (to be replaced with reservoir gas when it becomes available) was chosen to mitigate risks associated with sand production (as experienced during Alkaid flowback). The choice of artificial lift has no bearing on the quality of the reservoir. Given the performance of the well thus far, a change in artificial lift is being considered.

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14) Completion/frac design learnings and cost reduction for future wells

What were the key Dubhe frac/completion design parameters (proppant intensity, stage spacing, etc.), what has been learned so far, and what changes could reduce costs or improve outcomes on future SMD-B wells (including acidization, longer laterals, pilot hole necessity, diagnostics/tracers)?

The completion was executed efficiently and delivered all objectives per the design. There were 25 stages, on average employing approximately 2000 pounds of sand and 44 barrels of water per foot of completed lateral. As with all operators, we anticipate learning to improve well productivity and value. It is premature to conclude what changes we will make to our design until the flowback period is complete in this case.

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15) Reservoir quality and geologic questions (tightness, variability, location)

Why are the reservoirs so tight in this area, do SMD-B properties improve away from the Dalton Highway/Dubhe location, and can management share key rock properties (porosity/permeability/oil saturation) that supported drilling the lateral?

The topic of reservoir quality has been covered in various previous webinars and disclosures.

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16) Pad activity/logistics observations and whether activity reflects oil haulage

Can management confirm whether observed pad activity (including potential truck-loading cycles) reflects normal testing/handling operations or active oil haulage, what the current logistics cadence/costs are, and whether winter logistics are representative of future steady-state development costs?

As stated in the December 2025 webinar, approximately 100,00 barrels of water were produced with smaller amounts of oil and steady gas. The observed logistics activity was dominated by the transportation of produced water to a location approximately 20 miles north within the Prudhoe Bay Unit. The transportation was required because no produced water wells or facilities are currently installed at our pad site. Our development plans include on-site management of water.

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17) Gas composition/value, CO2/helium, pipeline readiness, and monetization

What is the composition and commercial value of the gas being produced at Dubhe-1 (CO2 content/pipeline readiness, helium content, volumes relative to expectations), is Pantheon selling gas during appraisal, and how does the pause in Dubhe testing affect the gas line/GSA timeline?

Gas samples from flow back to date indicate consistent CO2 content (low levels) with other associated gas in the Ahpun and Kodiak fields. The higher concentrations of helium were measured only during the coring and testing of Theta West-1. Further appraisal will be required to determine the scale and producibility of helium on the North Slope.

Pantheon is not selling gas during the Dubhe-1 well programme. Pantheon’s programme is not on the critical path for the gas line project, but we believe that Ahpun and Kodiak would be the best value gas for consumers when compared to other potential suppliers which entail higher development costs.

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18) Gas Sales Agreement: status, milestones, and timeline (incl. Glenfarne)

What is the status of discussions with Glenfarne/8 Star, what milestones are needed to convert the current framework into a binding gas sales agreement, and when does management realistically expect finalization?

The Company remains in discussions to finalize a fully termed gas sales agreement. As disclosed by Glenfarne in January 2026, they are progressing at pace to complete gas supply agreements to underpin the project. Any agreement between the parties will be subject to final investment decisions. A link to Glenfarne’s January 2026 update is provided here.

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19) Alaska LNG pipeline scenario: economics and impact on oil recoverability

If Alaska LNG pipeline proceeds, could Ahpun/Alkaid be economic primarily as a gas play, and how would large-scale gas offtake affect crude recoverability and overall field value?

The value of our portfolio is driven by liquids. Whilst gas sales could provide a meaningful revenue stream, it is not deemed economic to develop the assets for gas only.

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20) Commerciality/reserves implications if Dubhe underperforms + “Plan B”

If Dubhe-1 does not prove commercial, does that imply Ahpun is non-commercial, what are the reserves/resource consequences, and what is the Company’s contingency plan/alternative strategy?

The Dubhe-1 well targets the Eastern edge of the Southern section of the Ahpun Shelf Margin Deltaic-B reservoir. At this time the well is still under active appraisal. This accumulation is one of several satellite reservoirs surrounding the much larger Kodiak basin floor fan. Depending on the outcome, the development plan will focus on the highest value option amongst the full suite of reservoirs under appraisal.

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21) Kodiak strategy and farm-out/JV parameters

What is the current Kodiak strategy (why/when prioritize it), what magnitude of farm-out interest is being contemplated, what’s the plan if a partner cannot be secured, and how will management balance Ahpun vs Kodiak capital allocation?

Kodiak is the largest and most attractive asset in the portfolio. The 2023 strategy sets out that development of satellite fields along the Dalton highway will fund a large portion of an ultimate Kodiak development via free cash flow generation. This is why recent appraisal efforts have been prioritized to the satellite fields near infrastructure. Once this appraisal is complete, the Company will determine whether to continue with this approach or move directly to a Kodiak development. In that event, given the scale of the Kodiak resource and the associated capital requirements, the Company will continue to entertain farm-in discussions.

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22) Helium optionality at Theta West / re-entry feasibility

Is there a viable helium appraisal/development option at Theta West-1 (including re-entry feasibility), and could that be used to help fund further appraisal/de-risking?

Helium was present in samples collected from the Theta West-1 well in small concentrations. Whilst this is a significant upside to a Kodiak development given the market value of Helium, the small concentrations entrained in the associated gas are insufficient for a stand-alone Helium development. Any extraction of the helium would also include all other reservoir fluids (oil, water and natural gas).

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23) Megrez-1 hindsight: technical choices and lessons learned

What were the key technical decision points around Megrez-1 (e.g., why not run RFT in a vertical well), what went wrong, and what changes have been made to avoid repeating those mistakes?

The Company has addressed this in prior webinars. Whilst not a priority for the near term, the Company will revisit potential of this resource in due course.

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24) Short selling, market abuse concerns, and company response

What measures is management considering to address short selling/“bear attacks,” improve market confidence and liquidity, and respond more consistently to misinformation or negative campaigns?

The Board and Management believes that the Company’s disclosures are accurate and appropriate. The Company will continue to focus on operational and regulatory-compliant disclosure and does not comment on short-term share price movements, speculation or trading activity.

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25) Management alignment: insider buying, incentives, and timing constraints

What is management’s approach to demonstrating alignment with shareholders (open-market buying vs options), and can you address concerns around limited insider buying - both in terms of intent and any policy/closed-period constraints?

The Remuneration Committee replaced all prior incentive programmes and introduced a new share incentive plan in 2024 which sought to increase alignment between management and shareholders by paying up to 1/3rd of their remuneration in shares. This had the complementary effect of reducing the extent of share dilution through annual options grants to management, replacing them with less dilutive Restricted Stock Units (“RSUs”).

A comprehensive benchmarking process was conducted as part of this exercise to ensure that total compensation was aligned with UK peers but this also revealed that the total packages for Pantheon executives fall short of those typical in the USA. The Remuneration Committee is working in the interests of shareholders to retain the appropriate talent.

The Company has a statutory close period 30 days before the announcement of Interim and Financial results. The Company is also in a closed period when it is in position of unpublished Inside Information (as defined by MAR). The Company has an obligation to report all price sensitive news without delay save for when there is a legitimate reason for delaying such disclosure under MAR. For obvious reasons Public Companies do not discloses when they are in a Close Periods or not.

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26) Valuation / “fair value” / desired share price / ROI timeline / buyout talk

What does management view as a fair valuation range for Pantheon today (and longer-term on success), what share price would reflect that, what catalysts could close the gap, and when might long-term shareholders realistically expect ROI? Separately, has the Board considered strategic alternatives (partial/whole asset sale), and what would drive that decision?

The Board and Management do not provide guidance on valuation or share price expectations, noting that the Company’s share price is affected by a range of factors, many of which are outside its control, including market conditions, commodity prices and investor sentiment. The Company will disclose progress against operational and technical milestones in accordance with its regulatory obligations and does not speculate on market impact. The timing of shareholder returns remains inherently uncertain and is dependent on technical, commercial and market factors, with the Board focused on execution and long-term value creation.

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27) Development timeline, first production/first cash flow, breakeven, and FID

What is the updated timeline to first production and meaningful cash flow (including 2026 expectations), when does the Company expect to reach breakeven, and how does current progress affect the targeted FEED/FID and the broader 2028 plan?

The Company is analysing all information gathered to date and we will inform shareholders as development plans evolve.

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28) Dubhe mechanics and integrity: blockages, sand, over-frac, stage contribution

Have there been any mechanical or completion issues at Dubhe-1 (blockages, sand/solids, etc.), is there evidence all stages are contributing, and is there any concern the well was “over-fracked” or that fluid has migrated in a way that impairs performance?

The operation to drill and complete the Dubhe-1 well met expectations both in terms of the timeline and mechanical integrity of the well. Fracking was completed in a week – substantially more efficient than prior operations because of the choice of pumping contractor and its performance. There is no indication of any blockage and careful flow back protocols appear to have limited sand production. The effectiveness of the stimulation can be assessed at completion of the flow back and testing operations.

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29) Accounting/reporting and governance

When will the Company publish final results for FY ended 30 June 2025, will it provide an up-to-date cash (net of payables) figure, and what is the governance response to concerns about prior directors’ share dealings and potential asset write-downs?

Year end results were published on December 30, 2025. Cash on hand was reported in the RNS prior to the webinar and was not expected to change materially at the time of publication. Balance sheet assets are reviewed on a continuing basis and any permanent diminution of value will be reflected at the time it is assessed.

With regard to prior Directors, both Jay Cheatham and Robert Rosenthal retired from the Company in 2025 and at each respective time ceased to be subject to the Company’s share dealing code and are covered by obligations under the UK Market Abuse Regulation and, where applicable, US securities laws governing trading by US persons in relation to securities of non-US issuers.