WTI (Dec) $58.49 -$2.55, Brent (Jan) $62.71 -$2.45, Diff -$4.22 +10c
USNG (Dec) $4.53 -4c, UKNG (Dec) 81.26p -0.61p, TTF (Dec) €30.56 -€0.93

Oil price

Oil has rallied today after yesterday’s sharp fall, the API inventory stats showed a build in crude of some 1.3m barrels, slightly less than the 1.7m whisper. Gasoline drew by 1.4m whilst distillates added 944/- b’s as cold weather has yet to arrive. 

Following up from yesterday when the IEA unsurprisingly back tracked on its ludicrous forecasts and said that global oil consumption would now grow until 2050, not 2030 as before and that in that year demand would be 113m b/d, how we laughed…

PetroTal Corp

PetroTal has reported its operating and financial results for the period ended September 30, 2025. All amounts herein are in United States dollars unless stated otherwise.

Selected financial and operational information outlined below should be read in conjunction with the Company’s unaudited consolidated financial statements and management’s discussion and analysis (“MD&A”) for the period ended September 30, 2025, which are available on SEDAR+ at www.sedarplus.ca and on the Company’s website at www.PetroTal‐Corp.com.

Key Highlights of Q3 2025 Financial & Operational Results

• Average Q3 2025 sales and production of 18,028 and 18,414 barrels of oil per day (“bopd”), respectively;
• Generated adjusted EBITDA(1) and free funds flow(1) of $31.6 million ($19.03/bbl) and $12.1 million ($7.29/bbl) , respectively;
• Capital expenditures of $19.7 million, an increase of $2.6 million compared to the prior quarter;
• Net income of $3.6 million ($2.17/bbl), a decrease of $13.9 million compared to the prior quarter;
• Total cash of $141.5 million, essentially flat to the prior quarter, and an increase of $8.4 million compared to the same period last year;

(1) Non-GAAP (defined below) measure that does not have any standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures presented by other entities. 

Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented:
“I am pleased to share that PetroTal delivered solid financial results in the third quarter of 2025. Our production increased by 21% compared to the same period last year, supported by healthy river exports, as we continued to benefit from the results of our 2024 development drilling program. While we experienced some unscheduled downtime that temporarily impacted production capacity, our operational teams responded quickly to restore output and sustain our sales volumes.

Looking ahead, we continue to refine our development plan as we finalize our 2026 budget. In a separate announcement today, we have confirmed that PetroTal’s Board of Directors has decided to suspend our quarterly dividend for the time being. Although this was a difficult decision, we believe it is prudent to preserve liquidity as we evaluate the optimal development plan for the Bretana field. We thank our shareholders for their ongoing support and look forward to providing additional details with our 2026 budget in January.”

This is actually a good set of quarterly results as good production of 18,414 b/d stems from a strong drilling programme last year, favourable river conditions and good reservoir management which has led to positive EBITDA and importantly strong free funds flow. Total cash of $141.5m reflects this and as management always has, indicates that the desire for sensible cash preservation is at the forefront of the board’s mind. 

But, as the dividend announcement below shows, the payment has been suspended as a matter of prudence as the company looks into its operational performance over the next year, along with a careful scrutiny over costs and specific expenses. This has been on the back of a temporary, short term output fall which is down to the rig availability and not because of any reserves shortfall. 

This detailed analysis of the 2026 budget has led to a wise look at netbacks, at $60 oil they are down and it is certainly wise to ensure that drilling is tightly controlled as to costs, both in terms of workover opportunities and the planning for a new programme over Bretana and the rest of the portfolio. This will include the erosion control expenditure which is ongoing but will eventually end and leave the estate in a stronger position.

But there are plenty of good things to look forward to as PetroTal looks ahead to 2026, primarily that the reserves in the portfolio, clearly at Bretana and block 131 are still very good and a tight grip on matters such as water production will be key. Also there appears to be scope to tighten up margins on transport and with multi-optionality with regard to offtake partners netbacks could be improved here.

Overall I am satisfied that the management team, whom I know to be of the highest possible class, from operations to finance and particularly from the non-exec advice available which I consider to be absolutely top notch are doing a good, if difficult job. 

I am convinced that it has been a sensible, pragmatic decision to postpone the dividend whilst focusing on a return to production growth next year. This policy of concentrating on mid to long term growth whilst preserving short term liquidity in order to ‘evaluate the optimal development plan for the Bretana field’ is understandable. 

The shares have understandably taken a hit today, we have all I suspect been surprised but I still believe that with world class assets, a prudent and interactive board who are not shy to make difficult decisions it is not time to throw the baby out with the bath water, easy to say I know but PetroTal stays in the Bucket list for all the above long-term reasons.

Selected Financial Highlights

1.  Approximately 99% of Q3 2025 sales were through the Brazilian route vs 90% in Q2 2025.
2. Royalties include the impact of the 2.5% community social trust.
3. Non-GAAP (defined below) measure that does not have any standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures presented by other entities. See “Non-GAAP Financial Measures” section.
4. Net operating income represents revenues less royalties, operating expenses, and direct transportation.
5. Adjusted EBITDA is net operating income less general and administrative (“G&A”) and plus/minus realized derivative impacts.
6. Market capitalization for Q3 2025, Q2 2025 and Q3 2024 assume share prices of $0.42, $0.50, and $0.47 respectively on the last trading day of the quarter.
7. Free funds flow is defined as adjusted EBITDA less capital expenditures. See “Non-GAAP Financial Measures” section.
8. Includes restricted cash balances. 

Additional financial and operational updates during and subsequent to the quarter ending September 30, 2025:

Block 95 Update

PetroTal produced an average of 17,938 bopd from the Bretana field in Q3 2025, an increase of 21% over the same period last year. As disclosed on September 22, 2025, the Bretana field has been producing below capacity since mid-August, due to leaks in production tubing which necessitated the shut-in of five producing wells. Responding to the production downtime, PetroTal mobilized a service rig from Block 131 to Bretana and began a pulling campaign to restore production from shut-in wells in late October. As of November 10, the Company successfully replaced production tubing in one (1) well. During the first 10 days of November, Bretana production averaged 14,983 bopd, bringing 2025 YTD production to 6.2 mmbbls, for an average of 19,594 bopd.

Block 131 Update

Los Angeles field production averaged 476 bopd in Q3 2025, a decline of approximately 50 bopd compared to the prior quarter. PetroTal conducted a workover campaign at Los Angeles in September, which necessitated the shut-in of all three producing wells at the field for approximately one week. Following the completion of the workover campaign, Los Angeles field production averaged approximately 560 bopd during the month of October, compared to 479 bopd during the month of August, the last full calendar month before the wells were shut-in. As of November 11, YTD production from Los Angeles totaled just over 170,000 bbls, for an average of 539 bopd. PetroTal’s technical team is currently evaluating the results of the workover program, with a view to finalizing the 2026 development plan by mid-January 2026.

Bretana Erosion Control Project

The Bretana Erosion Control Project, which PetroTal is undertaking to ensure maximum realization of its investment in the Bretana field, continues to proceed on schedule. PetroTal expensed $6.5 million of erosion control costs in Q3 2025, up from $0.7 million in the prior quarter, as the main piling barge, along with the first batch of fabricated steel components, arrived at Bretana in mid-August. As of November 7, PetroTal is actively engaged in construction activities on breakwaters #1 and #3, both of which are situated in front of the village of Bretana. There are no material changes to project cost estimates or timelines at this time; PetroTal continues to target completion date in Q3 2026, with total project cost estimates falling within a range of $65-75 million.

Cash and Liquidity Update

PetroTal ended Q3 2025 with a total cash position of $141.5 million, compared to $133.1 million at the end of Q3 2024. Available cash as of September 30, 2025 amounted to $108.8 million, compared to $121.3 million at the same time last year. The increase in total cash primarily reflects the first tranche of the previously announced COFIDE/BanBif loan, which was drawn in Q2 2025. Of the $32.7 million that PetroTal carried as restricted cash on September 30, approximately $25 million was related to the escrow account of the COFIDE/BanBif loan.

PetroTal did not initiate any new production hedges during Q3 2025 and maintains coverage on approximately 1.0 million barrels over the period from October 1, 2025 to March 30, 2026. Consistent with prior disclosure, the costless collars have a Brent floor price of $65.00/bbl and a ceiling of $82.50/bbl, with a cap of $102.50/bbl. As of November 3, PetroTal’s existing production hedges had a present value of approximately $2.1 million.

Dividend announcement

PetroTal has announced that its Board of Directors has decided to suspend the Company’s regular quarterly dividend, until further notice. All amounts herein are in United States dollars unless stated otherwise.

Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented:
“While PetroTal’s financial and operational results remain strong, as evidenced by the Q3 2025 results which we also published today, the Company is facing a number of challenges as we finalize our 2026 budget. Most notably, we continue to experience delays in the resumption of our development drilling program, and as a result our production volumes are expected to decline throughout H1 2026. The updated production forecast, combined with weaker oil prices, is limiting our ability to fund both an adequate development program and return capital to shareholders.

After considering the preliminary 2026 outlook over the past few weeks, PetroTal’s Board of Directors has made the difficult decision to suspend our regular quarterly dividend for the time being. As a significant shareholder myself, I would like to assure investors that this decision was not taken lightly; we are evaluating all options to preserve liquidity, as we work to resume our development drilling program as quickly as possible. PetroTal intends to provide more detailed guidance in January 2026, once the development program and associated production forecast are finalized. We thank our shareholders for their ongoing support.”

Preliminary 2026 Outlook

As disclosed with Q2 2025 results on August 7, PetroTal is actively optimizing the long-term Bretana field development plan, to account for a variety of factors including sustained lower oil prices, regulatory considerations, and delays in resuming our development drilling program. At this point, PetroTal believes the best-case timing to resume drilling at Bretana is mid-year 2026. Given that PetroTal does not currently expect to generate any material organic production additions in H1 2026, initial 2026 budget runs suggest corporate production is likely to average approximately 12,000-15,000 bopd next year, depending on the timing of the resumption of development drilling at Bretana. PetroTal continues to refine the 2026 development plan, which remains subject to board approval.

While the long-term outlook for the Bretana field remains strong, supported by eight (8) and sixteen (16) booked 1P and 2P drilling locations, respectively, along with significant unbooked upside in the VS1 horizon, continued development is contingent on investment in facility expansion, specifically water handling capacity. At prevailing oil prices, and under the updated production forecast, PetroTal believes it will be challenged to fund both development drilling and expansion of water handling capacity internally through cash flow, while returning capital to shareholders. As a result, PetroTal’s Board of Directors is prioritizing cash preservation, with the expectation that available cash reserves may be drawn upon to help fund the 2026/27 development program. PetroTal intends to provide formal 2026 guidance by the end of January 2026 and publish its annual reserve report by the end of February 2026.

Dividend Suspension

After giving careful consideration to the 2026 outlook described above, PetroTal’s Board of Directors has elected to suspend the regular quarterly dividend until further notice. PetroTal’s Board of Directors has a long-standing directive that the Company must maintain a minimum available cash balance of $60 million, as insulation against production interruptions, decreases in commodity prices, or other emergency situations. If PetroTal’s Board of Directors has a reasonable expectation that forecast development expenditures may cause available cash to fall below $60 million within the next four quarters, it is obliged to reduce or halt distributions to shareholders.

PetroTal’s Board of Directors would like to assure investors that the Company remains committed to returning capital to shareholders whenever appropriate, whether through dividends or share buybacks. Since 2023, PetroTal has returned almost $155 million to shareholders, of which $144 million has been paid out in dividends. The Bretana field has generated more than $400 million of free funds flow since the beginning of 2020. PetroTal’s Board of Directors is confident this asset can continue to support a stable return of capital program in the future, albeit at higher production volumes and commodity prices. However, the Company must invest capital in development over the next 12-18 months to support these endeavors.

Reabold Resources/Union Jack Oil

The article below from OIL PRICE was forwarded to me and I find it very interesting. UK utility stocks are rallying based on the view that their grid connections could be worth a fortune to data centre projects. It should be worth noting that others are also preparing for such an uplift.

At Reabold they and UJO are planning to provide dedicated power for a major data centre project, bypassing the grid completely, creating a natural gas market at the well head. Whilst this is nascent technology the demand has excellent visibility and I consider it to be potentially a highly profitable part of the distribution network as we move into the data centre age. 

This in turn would mean a significant valuation for both companies, any implied number would be a significant uplift for either company and conservatively be worth a multiple of their market capitalisation. I have said recently that the upcoming year or so are looking highly promising, watch this space.

Drax Group Plc shares surged to their highest level in over three years as investors bet that UK utilities could become major beneficiaries of the country’s rapidly expanding data center industry.

The company’s stock rose as much as 8.5% after Germany’s RWE AG revealed a €225 million ($261 million) gain from selling a UK data center project, sparking optimism about the value of converting former power sites into hubs for energy-intensive digital infrastructure. The news reinforced investor confidence in Drax’s own plan to host a data hub at its flagship biomass power station in North Yorkshire.

Barclays analysts Dominic Nash and Peter Crampton said in a note that the market is “overlooking the upside potential in Drax,” estimating that its 250-acre site, which already has grid connections, could be worth as much as £500 million if developed for data hosting.

Data centers are among the fastest-growing sources of power demand globally, with the UK grid struggling to keep pace. These facilities now represent more than half of all new grid connection requests and could eventually consume electricity equal to roughly one-third of Britain’s current peak demand. Redeveloping existing industrial or power generation sites offers a practical way to bypass grid congestion, but such properties are increasingly valuable and scarce.

RWE’s deal reportedly valued the project at about €1 million per megawatt of grid capacity. Chief Financial Officer Michael Müller said the company is evaluating “around 10 projects” of similar size across Europe and confirmed that valuation levels of “about a million euros per megawatt” remain consistent across markets.

For Drax, the data center project could also extend the utility of its biomass plant, which will operate less frequently under a new UK government subsidy agreement. Earlier this year, Drax said it aims to build a 100-megawatt data center at its site by 2030, a move that could diversify revenue as demand for digital power surges.

Touchstone Exploration

Touchstone has reported its financial and operating results for the three and nine months ended September 30, 2025. Selected financial information is outlined below and should be read in conjunction with Touchstone’s September 30, 2025 unaudited interim condensed consolidated financial statements and related Management’s discussion and analysis, both of which are available online on the Company’s profile on SEDAR+ (www.sedarplus.ca) and website (www.touchstoneexploration.com). Unless otherwise stated, all financial amounts presented herein are in United States dollars.

Third Quarter 2025 Highlights

·      Production: Averaged 5,141 boe/d in the third quarter of 2025 (71 percent natural gas), compared to 4,399 boe/d (69 percent natural gas) in the second quarter of 2025 and 5,211 boe/d (75 percent natural gas) in the third quarter of 2024. Central volumes contributed approximately 2,217 boe/d during the third quarter.

·      Petroleum and Natural Gas Sales: Totaled $12.70 million, a 4 percent decrease from $13.25 million recorded in the comparative prior year quarter.

–     Crude oil sales: $5.84 million from average production of 1,051 bbls/d at an average realized price of $60.30 per barrel.

–     NGL sales: $1.34 million from average production volumes of 436 bbls/d at an average realized price of $33.41 per barrel.

–     Natural gas sales: $5.52 million from average production of 21.9 MMcf/d (3,654 boe/d) at an average realized price of $2.74 per Mcf.

·      Operating Netback: Generated $5.86 million in operating netback, a 21 percent decrease from the third quarter of 2024, primarily due to decreased petroleum and natural gas sales and related royalties and increased natural gas operating expenses.

·      Funds Flow from Operations: Declined to $0.74 million from $3.02 million in the prior year equivalent quarter, largely driven by lower operating netbacks, higher cash finance expenses, and increased current income taxes, partially offset by lower transaction costs.

·      Net Loss: Recorded a net loss of $2.06 million ($0.01 per share) compared to net earnings of $1.85 million ($0.01 per share) in the third quarter of 2024. The variance was primarily driven by the decrease in year-over-year funds flow from operations, $1.50 million in additional depletion and depreciation expense, and the absence of a $0.78 million gain on asset disposition recognized in the prior year.

·      Capital Investments: Invested $9.60 million with the majority of expenditures focused on Cascadura drilling operations and the procurement of compression equipment for the Cascadura natural gas processing facility.

·      Convertible Debt Financing: Issued a three-year secured convertible debenture (the “Debenture”) on August 8, 2025, bearing interest at 5 percent per annum to a private investor. The Debenture is convertible at approximately US$0.22 (C$0.30) per share and the investor received 6,250,000 warrants exercisable at C$0.40 per share for two years. Proceeds from the financing supported the completion of the Company’s Cascadura development drilling activities.

·      Financial Position: Net debt increased to $77.75 million at September 30, 2025, reflecting the issuance of the Debenture.

·      Strategic Disposition: Entered into an agreement to divest the non-core Fyzabad property to a Trinidad-based third party for consideration of three turnkey drilling wells on the Company’s WD-8 and WD-4 blocks. The property contributed average production of 49 bbls/d during the third quarter of 2025, with $2.59 million in net liabilities classified as held for sale at September 30, 2025. The transaction remains subject to customary regulatory approvals.

Post Period-end Highlights

·      Private Placement: On October 30, 2025, Touchstone raised gross proceeds of approximately $9.1 million (£7 million) from the issuance of 63,636,363 common shares at 11 pence sterling (approximately C$0.205) per share.

·      Bank Waiver Obtained: Following completion of the October private placement, Touchstone received a waiver from its lender, which waives the testing of the debt service coverage financial covenant under its loan agreement for the year ended December 31, 2025.

·      Production Update: Field-estimated production for October 2025 averaged 4,691 boe/d, a 3.3 percent decrease from 4,852 boe/d in September. The decline primarily reflected approximately two days of planned maintenance at the Central facility. Estimated October production volumes comprised 19.7 MMcf/d of net natural gas production (3,289 boe/d) and 1,402 bbls/d of net crude oil and liquids production.

·      Drilling Update: The drilling rig is currently being mobilized to the newly constructed Central block location to drill a well targeting a previously identified natural gas zone with bypassed pay potential. Any successful results are expected to be tied into the Company’s existing natural gas processing facility in the first quarter of 2026.

Paul Baay, Chief Executive Officer, commented:
“Third quarter production reflected strong performance from the Central field and the stabilization of existing wells at both Cascadura and Coho, with legacy oil production continuing to underpin our low decline rates.

The Cascadura-5 well commenced production on November 1, 2025, as planned; however, initial rates did not exhibit the high flush production observed in previous wells. Notably, for the first time, we encountered 26-degree API gravity crude oil from Cascadura. This represents an important new data point, adding further complexity to our understanding of the field’s structure.

While oil produced at Cascadura is approximately four times more valuable than natural gas on a per-boe basis at current pricing, initial production rates were below expectations. However, based on newly acquired data, we have identified additional reservoir intervals for perforation in both the Cascadura-2ST1 and Cascadura-5 wells. Encouragingly, these zones are capable of producing water-free oil and can be accessed at minimal cost without the use of a service rig.

We now have an opportunity to re-evaluate and refine our reservoir model at Cascadura as we advance drilling at the Central block and proceed with the compression installation at Cascadura, which remains on schedule to commence operations in the second quarter of 2026. All Cascadura wells, including Cascadura-2ST1 and Cascadura-5, are expected to benefit from compression. In addition, we have completed reprocessing of the three-dimensional seismic data, which will be integral to ongoing field evaluation.

The Central asset continues to outperform the estimates established at the time of acquisition. As we enter the next phase of development, we plan to drill up to four additional development wells and may conduct fracture stimulations on two existing wells. The drilling rig is currently mobilizing from Cascadura to the Central field, where it is expected to remain for the next year as we optimize production and prepare for the anticipated natural gas price increase stipulated in our marketing contract in May 2027.

We also continue to work constructively with the National Gas Company of Trinidad and Tobago on revising gas pricing at Cascadura, as current pricing does not adequately reflect the capital intensity of development or align with that received by other producers in the country.“

After the disaster of the raise in the summer, in which at no fault of their own, the money failed to show, Touchstone have refinanced and are rebuilding and whilst that has been complicated by the Cas-5 resultn which now includes oil in the process.  

The company will now drill up to four wells on the Central field and frac two others, any success brings higher prices on distribution. Also the negotiations with the NGCTT deserve to be successful given the level of activity. 

Third Quarter 2025 Financial and Operating Results Overview 

Notes:

(1)    Refer to “Advisories – Product Type Disclosures” for further information.
(2)    Refer to “Advisories – Oil and Natural Gas Measures” for further information.
(3)    Specified or supplementary financial measure. Refer to “Advisories – Non-GAAP Financial Measures” for further information.

Cascadura-5 Well Update

Cascadura-5 was successfully brought onstream as planned on November 1, 2025, and is currently producing through a 70 percent choke to the Cascadura natural gas facility. Since coming online, the well has averaged gross production of approximately 500 boe/d, comprised of liquids-rich natural gas and 26-degree API gravity crude oil, with no associated water.

Cascadura-5 is the first well in Block B to produce medium-gravity crude oil in addition to natural gas. Preliminary production data suggest that a lower sand interval perforated in the well is contributing a crude oil leg. This result will be evaluated further to determine the potential for optimization opportunities in existing Block B wells and to assess future development implications across the block.

2025 Outlook and Revised Guidance

On October 24, 2025, the Company released its revised 2025 operational and financial guidance (the “Revised Guidance”). Following initial production results from Cascadura-5, Touchstone provides the following updates (the “November Guidance”) to the Revised guidance.

Notes:

(1)    Forward-looking statement and financial outlook information based on Management current estimates. Refer to “Advisories – Forward-looking Statements”.
(2)    As disclosed in the Company’s October 24, 2025 announcement.
(3)    Specified or supplementary financial measure. Refer to the “Advisories – Non-GAAP Financial Measures” section of this MD&A. 

Since coming online on November 1, 2025, the Cascadura-5 well has produced estimated gross average daily volumes of 2.4 MMcf/d of natural gas and 106 bbls/d of crude oil (approximately 506 boe/d), below the Revised Guidance, which had anticipated gross volumes of approximately 17.0 MMcf/d of natural gas and 275 bbls/d of associated liquids (approximately 3,108 boe/d) over the initial 30 days.

Based on this lower-than-expected performance, the Company now expects 2025 average daily production of 4,700 boe/d, representing a decrease of approximately 300 boe/d (6 percent) relative to the 5,000 boe/d midpoint in the Revised Guidance.

As a result of the forecasted decline in production, the Company expects funds flow from operations of approximately $4 million for 2025, down from $6 million in the Revised Guidance.

Capital expenditures are expected to total $27 million, representing a nominal $1 million increase compared to the Revised Guidance. 

Reflecting the anticipated reduction in funds flow from operations combined with the higher capital program, Touchstone now expects to exit 2025 with net debt of approximately $69 million, an increase of $4 million (6 percent) relative to the $65 million disclosed in the Revised Guidance.

Liquidity

Touchstone’s near-term development strategy remains focused on enhancing operating cash flows through continued field development activities. The Company will maintain a disciplined approach to future capital spending to preserve financial liquidity while executing its operational plans.

The September 30, 2025 unaudited interim condensed consolidated financial statements include a going concern statement. In a downside scenario, and in the absence of mitigating actions, the Company’s current cash resources may not be sufficient to fund expected operating and development expenditures and scheduled bank debt repayments over the next twelve months. These circumstances represent material uncertainties that may cast significant doubt on the Company’s ability to continue as a going concern.

As at September 30, 2025, Touchstone had a working capital deficit of $16.74 million, excluding the carrying value of the Debenture, which may be converted into common shares at any time prior to its August 2028 maturity. The Company’s going concern assessment is dependent on the timely collection of value-added tax receivables and anticipated incremental production from its 2025 development program, which has experienced additional costs and operational challenges to date.

In the event that expected cash inflows from value-added tax receivables and increased production are delayed, Management is evaluating and prepared to implement various contingency measures to address remaining capital requirements. These measures may include adjustments to planned operational activities and, if required, consideration of additional debt or equity financing.

Management continues to closely monitor the Company’s liquidity position to ensure that operating cash flows, available credit capacity, and working capital remain sufficient to support ongoing financial obligations, planned capital programs, and future work commitments.

Assumptions for November Guidance

Production estimates contained herein are expressed as anticipated average production over the calendar 2025 year. All production volumes disclosed herein are based on Company working interest before royalty burdens. In determining anticipated 2025 production, Touchstone considered historical drilling, completion, production results and decline rates for prior years and the year-to-date 2025 period. The key assumptions underpinning the November Guidance forecast for average daily production, funds flow from operations, and net debt are outlined below.

Notes:

(1)    Forward-looking statement representing Management estimates. See “Advisories – Forward-looking Statements”.
(2)    As disclosed in the Company’s October 24, 2025 announcement.
(3)    Non-GAAP financial measure. See the “Advisories – Non-GAAP Financial Measures” section herein for further information.

Variations in the amount of future equity raises, forecasted commodity prices, differences in the amount and timing of capital expenditures, and variances in average production estimates and decline rates can have a significant impact on the key performance measures included in the guidance disclosed herein. The actual results of the Company’s operations and the resulting financial results will vary from the amounts set forth in this announcement and such variations may be material.

Using the midpoint of the Company’s November production guidance and holding all other assumptions constant, a 20 percent increase (decrease) in forecasted average realized commodity prices would increase funds flow from operations by approximately $1.12 million (decrease by approximately $0.70 million). Assuming capital expenditures are unchanged, the impact on funds flow from operations is estimated to result in an equivalent decrease (increase) in forecasted year end 2025 net debt.

Non-GAAP Financial Measures

This announcement references various non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures as such terms are defined in National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure. Such measures are not recognized measures under Canadian Generally Accepted Accounting Principles (“GAAP”) and do not have a standardized meaning prescribed by IFRS Accounting Standards as Issued by the International Accounting Standards Board (“IFRS”) and therefore may not be comparable to similar financial measures disclosed by other issuers. Readers are cautioned that the non-GAAP financial measures referred to herein should not be construed as alternatives to, or more meaningful than, measures prescribed by IFRS, and they are not meant to enhance the Company’s reported financial performance or position. These are complementary measures that are commonly used in the oil and natural gas industry and by the Company to provide shareholders and potential investors with additional information regarding the Company’s performance. Below is a description of the non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures disclosed herein.

Operating netback

Touchstone uses operating netback as a key performance indicator of field results. The Company considers operating netback to be a key measure as it demonstrates Touchstone’s profitability relative to current commodity prices and assists Management and investors with evaluating operating results on a historical basis. Operating netback is a non-GAAP financial measure calculated by deducting royalty and operating expenses from petroleum and natural gas sales. The most directly comparable financial measure to operating netback disclosed in the Company’s consolidated financial statements is petroleum and natural gas revenue net of royalties. Operating netback per boe is a non-GAAP ratio calculated by dividing the operating netback by total production volumes for the period. Presenting operating netback on a per boe basis allows Management to better analyze performance against prior periods on a comparable basis.

Capital expenditures

Capital expenditures is a non-GAAP financial measure that is calculated as the sum of exploration and evaluation asset expenditures and property, plant and equipment expenditures included in the Company’s consolidated statements of cash flows and is most directly comparable to cash used in investing activities. Touchstone considers capital expenditures to be a useful measure of its investment in its existing asset base. 

Working capital and net debt

Working capital and net debt are capital management measures used by Management to monitor the Company’s capital structure to evaluate its true debt and liquidity position and to manage capital and liquidity risk. Working capital is calculated as current assets minus current liabilities as presented in the applicable consolidated balance sheet, excluding the carrying value of the convertible debenture. Management excludes the carrying value of the convertible debenture from working capital given the instrument has a maturity date in 2028.

Net debt is determined by adding the Company’s working capital surplus or deficit to the principal (undiscounted) balance of non-current bank debt and the principal (undiscounted) balance of the convertible debenture. Net debt is most directly comparable to total liabilities as disclosed in the Company’s consolidated balance sheets.

Supplementary Financial Measure 

Realized commodity price per boe – is comprised of petroleum and natural gas sales as determined in accordance with IFRS, divided by the Company’s total production volumes for the period.

Realized crude oil sales per barrel, realized NGL sales per barrel and realized natural gas sales per boe – are comprised of sales from the respective product type as determined in accordance with IFRS, divided by the Company’s total production volumes of the respective product type for the period. Crude oil sales, NGL sales and natural gas sales are components of petroleum and natural gas sales as disclosed on the consolidated statements of loss and comprehensive loss.

Realized crude oil and liquids sales per barrel – is comprised of the sum of crude oil and NGL product sales as determined in accordance with IFRS, divided by the sum of the Company’s total crude oil and NGL production volumes for the period. Crude oil and NGL sales are components of petroleum and natural gas sales.

Royalty expense per boe – is comprised of royalty expense as determined in accordance with IFRS, divided by the Company’s total production volumes for the period.

Royalty expense as a percentage of petroleum and natural gas sales – is comprised of royalty expense as determined in accordance with IFRS, divided by petroleum and natural gas sales as determined in accordance with IFRS.

Operating expense per boe – is comprised of operating expense as determined in accordance with IFRS, divided by the Company’s total production volumes for the period.

General and administration expense per boe – is comprised of general and administration expense as determined in accordance with IFRS, divided by the Company’s total production volumes for the period.

Cash finance expense per boe – is comprised of cash finance expense divided by the Company’s total production volumes for the period. Cash finance expenses are calculated as net finance expense as determined in accordance with IFRS, less accretion on bank debt, accretion on decommissioning obligations, and minor non-cash items, all of which are non-cash in nature. The Company discloses net finance expense as cash or non-cash to demonstrate the true cost of finance expense to assist Management with evaluating results on a historical basis.

Current income tax expense per boe – is comprised of current income tax expenses as determined in accordance with IFRS, divided by the Company’s total production volumes for the period.

For further information, please refer to the “Advisories – Non-GAAP Financial Measures” section of the Company’s most recent Management’s discussion and analysis for the three and nine months ended September 30, 2025 accompanying our September 30, 2025 unaudited interim condensed consolidated financial statements, both of which are available online on the Company’s profile on SEDAR+ (www.sedarplus.ca) and website (www.touchstoneexploration.com). Touchstone’s Management’s discussion and analysis is incorporated by reference herein and includes further discussion of the purpose and composition of the specified non-GAAP financial measures consistently used by the Company and detailed reconciliations to the most directly comparable GAAP measures.

Oil and Natural Gas Measures

To provide a single unit of production for analytical purposes, natural gas production has been converted mathematically to barrels of oil equivalent. The Company uses the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalent conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.

Product Type Disclosures

This announcement includes references to crude oil, NGLs, crude oil and liquids, and natural gas total and average daily production volumes. In accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), disclosure of production volumes must include segmentation by product type as defined in the instrument. In this MD&A, references to “crude oil” include the combined product types light crude oil and medium crude oil and heavy crude oil; references to “NGLs” refer to condensate and propane; and references to “natural gas” refer to conventional natural gas, all as defined in the instrument. References to “crude oil and liquids” include crude oil and NGLs.

The Company’s average field estimated production for October 2025 consists of the following product types as defined in NI 51-101 using a conversion ratio of 6 Mcf to 1 boe where applicable.

For further information regarding specific product disclosures in accordance with NI 51-101, please refer to the “Advisories – Product Type Disclosures” section of the Company’s most recent Management’s discussion and analysis for the three and nine months ended September 30, 2025 accompanying our September 30, 2025 unaudited interim condensed consolidated financial statements, both of which are available online on the Company’s profile on SEDAR+ (www.sedarplus.ca) and website (www.touchstoneexploration.com).

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