Cavvy Energy Ltd.

Good day, ladies and gentlemen, and welcome to the CABI Energy Q4 and full year 2025 Financial Results Conference Call. Please be advised, today's proceedings are being recorded. Following the presentation, we'll conduct a question and answer session. If you have a question you are viewing on the webcast, please use the Ask a Question button in the top right-hand corner and type your question in at any time during the presentation. If you are participating via telephone and would like to ask a question, please dial star 1 1 at any time. You will then be in the question You will then be in the queue for question and answer session at the end of the call. I would like to turn the meeting over to Mr. Dallas McConnell, Vice President of Corporate Finance. Please go ahead, Mr. McConnell.

Thanks, Kevin, and good morning. I would like to welcome everyone to CAVI's fourth quarter and full year 2025 conference call. With me today are President and Chief Executive Officer Darcy Redding, Chief Financial Officer Adam Gray, Chief Operating Officer, John Emery, and Chief Commercial Officer, Paul Kunkel. Darcy and Adam will begin today with a review of our operating and financial results and certain other company developments. Following their prepared remarks, we will turn the call over to the conference coordinator for your questions. Before Darcy begins, I would like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by CAVI with Canadian securities regulators on cdarplus.ca. With that, I will now turn the call over to President and CEO, Darcy Redding, who will provide more detail on our performance along with recent developments.

Thank you, Dallas, and thank you to all for your participation today and for any questions you may have at the end of this session. We're extremely pleased with our fourth quarter and full year 2025 results. Our commitment to our long-term business strategy is key to our corporate performance, and 2025 was a milestone year for CAVI. In 2025, we continued with our focus on the runtime reliability of our gas processing facilities, third-party processing revenue growth, cost structure reduction and operational excellence, and debt reduction. Our strong conviction to optimize assets and continuously improve cash flow and business performance delivered solid quarterly and annual 2025 outcomes. Additionally, we reached the end of the fixed price sulfur sales arrangement on December 31st of last year. This fixed pricing contract, applicable to the majority of our sulfur production, was in place since the Southern Foothills assets were purchased from Shell in 2019. The arrangement often limited our sulfur sales revenue to below market values, particularly in 2025 as we witnessed a significant and steady increase in the price of sulfur sold at Vancouver. We continue to see strong Vancouver sulfur pricing so far through the first quarter of 2026, generating tailwinds to our cash flow expectations this year. Adam and I will elaborate further on these matters over the next few minutes of the quarterly call. However, before we step into those details, I'd like to refresh the compelling reasons to invest in CAVI Energy. CAVI's low base production decline of approximately 6% annually is amongst the lowest of all Western Canadian producers. This means that only low capital investment is required to offset this natural decline. And conversely, production growth can be achieved with modest capital investment versus peers. Nearly 9,000 BOEs per day of dry gas production that is tied into a non-owned third-party facility remains voluntarily shut in due to the weakness in eco-natural gas price through last year and now into 2026. Most of this shut-in production is contractually dedicated to the third-party facility through 2027, after which time CAVI will be able to process the well production at the facility of our choice. I also note that approximately 300 metric tons per day of sulfur production is associated with this shut-in gas, which can help offset stubbornly low natural gas prices. The company's production capability, including shut-in volumes, is approximately 33,000 BOE per day, and our identified drilling inventory provides organic growth potential to achieve corporate volumes in excess of 50,000 BOE per day. We have materially grown our annual revenue stream from processing the third-party production at our owned and operated infrastructure. In fact, we corporately processed more than 136 million cubic feet per day in the fourth quarter of 2025. a key reason the company generated nearly $40 million of revenue from our midstream services in 2025. We expect continued growth in this revenue stream in 2026 and beyond as we strive to fill the remaining unutilized capacity of our gas processing facilities. And, as I mentioned a moment ago, our significant sulfur production, which is derived from the removal of hydrogen sulfide from our raw gas processing done at our facilities, has opened up an exciting and larger revenue stream for the company in 2026. We believe the potential value of this revenue stream is underappreciated and creates a very compelling investment opportunity on its own, with our guidance sulfur production expecting to deliver approximately 25% of our revenue stream in 2026. These attributes, along with our guidance to deliver $40 million to $50 million of debt reduction in 2026, creates an extremely compelling investment opportunity. Later in the call, Adam will provide additional detail on our per share net asset value that also strongly supports this. My case that CAVI represents an undervalued and attractive investment opportunity can be summarized by capturing the primary share price catalysts on this slide that I've already mentioned. In addition, CAVI is extremely well positioned to capture new business opportunities related to power generation and data center partnerships due to our significant natural gas production. Power generation from natural gas combustion remains the simplest, quickest, and most cost-effective means for generating power, which is the most important feedstock for data center development. In fact, CAVI's suitability for data center partnerships is even further enhanced because of the proximity and access of our facilities to power grids, fiber optic networks, existing water use permits, paved road and rail access, and to the City of Calgary and its international airport. I'd like to now focus on the highlighted accomplishments of the fourth quarter and full year 2025. We generated net operating income of nearly $21 million in the quarter and just over $110 million for the full year. AECO natural gas seasonal price strength did not materialize in the fourth quarter as anticipated, and particularly after most of 2025 experienced near unprecedented sustained lows, this was very disappointing. Fortunately, our strong commodity hedges resulted in realized hedging gains of nearly $13 million and $80 million in Q4 and for the full year, respectively. Our 23,000 BOE per day of fourth quarter production and almost 24,000 BOE per day of annual production was in line with our 2025 guidance and consisted of 80% natural gas and 20% natural gas liquids. This is a slightly higher liquid weighting than the 15% contribution that is typical when all of our shut-in dry gas production is online. Notable for 2025, but even more notable as we look forward to 2026, the company produced almost 1,100 metric tons per day of sulfur in 2025, despite approximately 300 metric tons per day of unrealized sulfur production associated with the shut-in dry gas previously mentioned. Of note, both hydrocarbon and sulfur production were slightly lower in the fourth quarter as compared to the full year, due primarily to the two and a half week planned outage at the Waterton Gas Processing Facility in October. This outage was a proactive decision to incur maintenance downtime in Q4 2025 when AECO gas pricing was weak and sulfur contract prices were low. Cash flow impact was thus minimized rather than if the downtime was deferred to early 2026 when much higher sulfur prices and cash flow impacts were anticipated. Net debt was reduced by $27 million in 2025, continuing a long-term trend of debt reduction that has totaled over $100 million since 2022. Adam will speak to our successful track record of debt retirement over the past couple of years in a few minutes. Subsequent to year end, an additional US dollar $27 million or approximately $37 million in Canadian funds of debt repayment was made year to date in 2026. This was done with cash realizations from the prepayment for a portion of our 2026 sulfur sales per the terms of our 2026 Sulphur Pricing Agreement. Additionally, $3.5 million of funds received from the March exercise of approximately 5.1 million warrants that were due to expire at the end of the month were used to supplement the debt repayment. I'll speak more about our 2026 Sulphur Pricing Agreement in a few moments and Adam will provide additional commentary on our debt management so I'd like to highlight a few details on the growth of our third-party processing business. Revenue derived from third-party processing and other services provided by CAVI will continue to be an important contributor to the company's long-term success. This revenue stream helps provide diversification away from relying solely on hydrocarbon sales revenue, since the fee revenue from these midstream services is largely independent of commodity price and is sourced from reliable counterparties. The chart in the upper left of this slide shows the steady growth in quarterly revenue generated from our customer-facing business, climbing to approximately $11 million in Q4 2025 and representing a compound annual growth rate of approximately 40% over the past two years. The chart in the lower right of this slide shows that approximately 65% of corporate third-party processing volumes were handled at our Caroline gas facility in the fourth quarter, with our Jumping Pound facility accommodating another one-third. Our Waterton gas processing facility primarily processes CAVI gas at this time. A quick look at the chart in the upper right of this slide shows the same third-party volumes represented by the lowermost blue segment of the bar. CAVI-owned volumes are depicted by the brown-colored segment, which show a slightly lower volume corporately in the fourth quarter as a result of the previously mentioned Waterton maintenance downtime. In aggregate, CAVI's three core operated gas processing facilities have raw gas processing capacity of approximately 420 million cubic feet per day. CAVI typically utilizes nearly 50% of this available capacity, while third-party volumes utilize another one-third. Filling the remaining 15% to 20% of currently available capacity remains a focus for CAVI as we consider investment in our own drilling inventory and strive to continuously grow our midstream business. I'd like to also note that CAVI has evaluated several de-bottlenecking and expansion opportunities for our highest utilized facility, Caroline, since we anticipate filling it through growth in raw gas feedstock. These opportunities will require capital investments with the magnitude of capital being dependent on the scale of the de-bottlenecking or expansion. We intend to secure appropriate volume and fee-based revenue commitments prior to investing in any type of capacity expansion, and the company's objectives will continue to focus on generating attractive returns on any capital deployed to enhance the facility's gas handling capabilities. As we first communicated in the third quarter 2025 earnings call back in November, CAVI entered into a forward sulfur pricing agreement for a one-year term beginning January 1, 2026. Calendar year 2025 witnessed a steady increase in the Vancouver sulfur price, which was virtually unprecedented, except for a sharp increase in price as a result of Russia's invasion of Ukraine in 2022. This price spike was followed by a remarkable and near instant drop back to breakeven pricing that materialized prior to the end of 2022. This 2022 event is shown with the yellow curve in the chart located in the lower right-hand side of this slide, which also shows the past 15 years of Vancouver sulfur price history, which has averaged about $150 per metric ton over that time. CAVI's original pricing arrangement, which was in place since 2019, expired at the end of 2025, providing much improved sulfur price exposure beginning in 26. The 26 pricing is based on a combination of the agreement that applies to two-thirds of our sulfur production and exposure to open Vancouver pricing on the remaining one-third. The Vancouver sulfur price has remained at or near $500 per metric ton into the first quarter of 2026, and recent geopolitical events in the Middle East are expected to support strong sulfur prices for the foreseeable future. We are currently exploring opportunities for sulfur price certainty for a portion of our sales in calendar years 2027 and 2028, and are optimistic that recent world events may generate favorable pricing conditions for these time periods. One point worth noting as it relates to CAVI's sulfur price exposure. Our benchmark is FOB Vancouver pricing. CAVI retains the costs incurred to handle and ship the sulfur product to Vancouver as stipulated in the 2022 agreement that governs this benchmark price. These terms apply through 2028 with an additional one year extension if the purchaser meets certain conditions. Finally, on this slide, we have updated the pricing matrix as compared to previous versions you may have seen in our previous corporate presentations. The matrix has been extended to capture higher Vancouver sulfur prices up to $525 per metric ton. This matrix, located in the lower left of this slide, shows the net after royalty sulfur sales revenue derived for the calendar year including the terms of our arrangement, at various combinations of sulfur production and Vancouver price. Illustratively, at CAVI sulfur production guidance of 1,000 to 1,150 metric tons per day, and at an average Vancouver price of $450 per metric ton, CAVI will generate approximately $100 million in net revenue from sulfur production. representing approximately 30% of the company's revenue stream. Turning now to our year-end 2025 reserves, which were independently evaluated by Deloitte, we realized a year-over-year increase in our total proved plus probable or 2P reserves of 7% to 261 million barrels of oil equivalent. Waterton is our largest reserve region with 42% of the corporate reserves assignment. The net present value of our 2P reserves at a 10% discount increased 20% year over year to $1.5 billion based on January 1st, 2026 consensus pricing. This data is displayed in more detail along the left-hand side of the current slide. As I mentioned earlier in this call, our approved developed producing or PDP production decline based on this evaluation is approximately 6% among the lowest of all natural gas producers in Canada. This extremely low decline and our large reserve base means our 2P reserve life index is nearly 26 years. These are clearly long life reserves with material development upside potential. Using our year-end independent reserve evaluation as the basis, I would like to now draw your attention to our net asset value calculations, obviously referred to as NAV on this slide. All of this information is shown in detail on the table in the middle of the slide. Given our NAV calculations incorporate the impacts of our debt and hedge positions, which Adam will be speaking to in more detail, this is a good time to turn the floor over to him. Adam will provide additional commentary on our NAV and on our operating and financial results.

Thanks, Darcy. Good morning and thanks again for joining. I'm Adam Gray, Chief Financial Officer. I'll touch briefly here on NAV and then move into providing an update on our key financial and operating results for the quarter and year end, our debt repayment progress, current hedge position, and an update on our 2026 guidance. As Darcy mentioned, our 2026 five NAV reconciliations in the middle of this slide and shows our PDP NAV at $423 million or $1.43 per share, which is a 19% increase over last year. As is standard, we calculate NAV by adjusting the reserve value for our actual balance sheet ARO and net debt. 1P NAV is $3 a share and 2P NAV is over $4 a share. Note that these share values are calculated after considering the recent warrant exercise dilution impact, which added just over 5 million shares or 1.7% to our share count. Recent increase in our share price has certainly closed some of the price to NAV valuation gap, but we're still trading at a 0.87X PDP NAV or a 13% discount to our current share price and at very large discounts to our total approved and 2P NAV. The quality and longevity of our assets, plus the speed at which we continue to reduce net debt, make me optimistic that we'll continue to see upside in our equity values. Okay, I'll move fairly quickly through Q4 and year-end operating and financial results. Q4 production averaged 23,000 BOEs a day, comprising 81% natural gas and just under 1,000 metric tons per day of sulfur. As Darcy mentioned, in early October, we chose to take our Waterton facility down for 16 days of preventative maintenance, which did impact our production results. Offsetting that, we were able to restart just under 3 million cubic feet a day of production from our dry, sweet northeast BC field in November, as gas prices rose above our break-even thresholds. Unfortunately, we chose to shut that field in again in early February as natural gas pricing deteriorated. And at the moment, it's not clear that we would bring that field back onto production until at least the fourth quarter of 2026. Finally, our third party processing volumes and revenue continue to grow strongly. Raw gas process hit 136.6 million cubic feet a day in the quarter, up 80% year over year. and drove processing revenues to $12.6 million for the quarter, up 135% year over year. Operating costs were $43.7 million, or just over $20.50 per BOE, which is our first quarterly increase in operating costs for some time, and primarily reflects higher Q4 power costs in the Caroline fields, as compression needs increased related to those revenue-generating third-party volumes. As you've heard me speak to in prior calls, adjusted operating expense is an important metric for us. As a reminder, a significant percentage of our operating cost is expended at our three gas processing facilities. In 2025, CAVI's owned production represented only 30% of the inlet volumes at Caroline, 57% at Jumping Pound, and 96% at Waterton. So spreading all of our total operating costs Only our portion of inlet volumes is not a particularly accurate comparability metric. Adjusted operating expense, which deducts third-party processing and sulfur revenues from operating expense, is certainly not a perfect measure, but it does allow us a better indicator of our comparability to peers. Turning to quarterly financial results, Q4 net operating income came in at $20.8 million, translating to $9.82 per BOE net back and about $0.07 per share. Funds flow were $13.5 million or $0.05 a share. These results were boosted by a $12.8 million hedging gain, which continues to be the swing factor. As without hedges, our cash flow would have been pressured by weaker-than-desired ACO and liquids pricing. especially prior to that sulfur contract price expiry. Realized AECO was $2.41 in MCF before hedging and $3.60 after hedging. WTI-linked condensate was $76.62 CAD before hedging and $79 after. It's hard to believe now with everything going on in the world that WTI was trading under US $60 per barrel for much of Q4. Recall that in Q4 2025, we were still subject to that contract sales price on our sulfur production of $6 per ton. So our realized sulfur price was $43.22 CAD, reflecting the small percentage of sales that were not subject to that $6 contract. Market pricing during the quarter rose to $414 a ton in Vancouver, translating to about $466 Canadian per ton at our plant gate. Capital expenditures were higher in Q4 than in previous, but still within guidance. There are a few reasons for that. First, we pushed to finish off a number of our optimization projects that we've been working on since the rights offering. We've incurred a total of about $10.8 million on that optimization program since the fourth quarter of 2024 and have generated an aggregate ROI of 147% on that investment. Next, we incurred some maintenance and turnaround capital at Waterton, as previously discussed, and getting ready for our Caroline turnaround project, which is planned for the third quarter of this year. And finally, our abandonment and reclamation program has a degree of seasonality because we've been targeting work up in Northeast BC, much of which is winter-only access. That program has continued into Q1. So after G&A of $5.7 million, and cash interest of $4.8 million, both of which came in as expected. We ended the quarter with net debt of $170.6 million, which is up a bit from Q3, primarily as a result of expenditures on our capital program during the quarter. Net debt is an internal calculation and is comprised of $151 million of actual debt and just under $20 million of a working capital deficit. which I suggest is a relatively healthy working capital ratio considering the timing of cash inflows and outflows in this particular business. Very briefly on annual results, as many of the themes I've already discussed for Q4 are relevant for the full year, production at 23,904 BOEs a day and sulfur production of just under 1,100 metric tons per day Those voluntary shut-ins Darcy mentioned of uneconomic dry gas impacted our annual production by about 8,700 BOEs per day and 300 metric tons per day of sulfur. The large operational impacts to our production during the year, in addition to those shut-ins, were the jumping pound Q1 downtime that we've talked about in previous calls and that Q4 discretionary preventative maintenance capital program. Otherwise, we had a very successful year from a reliability perspective. Operating costs for the year totaled $164.8 million, which is down 21 million or 11% from 2024 and down 27% from 2023. Our strategic focus to reduce operating expense on a total and per throughput unit basis continues to yield very positive results, and we are not done delivering efficiency improvements. You can see in the chart on the bottom right that the gap between operating expense per BOE and adjusted operating expense per BOE widened in 2025 as third-party processing revenues grow. And that gap will widen much farther in 2026 as SOLFR becomes a more meaningful revenue stream. Finally, as previously discussed, third-party volumes grew 86% year over year and revenues grew 92%. On annual financial results, Full year NOI came in at $110.5 million or $12.66 per BOE net back and $0.38 per share, which is a beat on our 2025 guidance of $100 to $110 million and 70% higher than 2024. Also of note, even though production was down 14% from 2024 on shut-ins, liquids pricing was meaningfully lower than 2024, Our net back nearly doubled year over year from $6.50 per BOE to $12.50 per BOE, and funds flow increased 225% from $19.63 million, all representing our success with ongoing efficiency and growth initiatives, which drove net back resilience despite weak commodity prices. Within those results, our hedging gain for 2025 was just under $80 million, so a substantial component of our operating income. But keep in mind that is less than the incremental sulfur revenue we expect to add in 2026, which could be over $100 million net of royalties. As Darcy mentioned, our ability to sell sulfur production at market prices both increases and diversifies our revenue on a non-correlated basis to our other revenue streams. All that said, we continue to desire a robust hedge portfolio over the medium term out to 2029. I'll discuss hedging a little bit more in a couple slides. Turning to debt reduction, as expected, the step change on debt comes in 2026, but we made good progress on deleveraging in 2025 with total debt down in the year by $22 million and net debt down by just under $27 million. Those reductions translated into year-over-year cash interest cost savings of over $4 million. As we've consistently messaged, reducing leverage remains our top capital allocation focus until total debt gets comfortably under a one times EBITDA ratio. We ended 2025 at 1.8 times based on an EBITDA of just under $90 million, so we have a ways to go. But this chart tells the story of how far we've come since 2023, with over 100 million of total debt reduction during a period of weak ACO prices and without meaningful access to our sulfur revenue. Part of that 2026 sulfur pricing hedge we did in the fall was an agreement that our counterparty would prepay for a certain portion of sulfur production. So as Darcy mentioned, in early January, we received just under 27 million US dollars which is a prepayment representing six months of approximately two-thirds of our expected sulfur production, which is the fixed and collared price components. Every month, we will settle and true up for actual prices and actual volume shipped, and we will receive a similar prepayment at the end of June for the second half of the year. Expect to see a large deferred revenue liability on the balance sheet at Q1, which represents the undelivered component of the prepayment and which will be reduced over time as it transfers to sales. With this prepayment and the most recent warrant exercise process, proceeds, and positive business results, we've already repaid $27 million or nearly $37 million CAD against our debt in 2026. fully repaying the balance of our revolver, which was at $18.1 million at the end of the year, and applying the remaining to our senior term loan. That prepayment represents about 23% of the total debt that was outstanding at the end of the year and takes us already into the lower range of our year-end 2026 debt repayment guidance, while also substantially improving financial flexibility with that fully undrawn $22 million U.S. revolver. Just a note on debt maturities, our debt tranches mature in March and September of 2027, so we continue to have lots of runway to repay and refinance that debt. Ideally, we will conclude a refinancing this calendar year to provide more certainty to our shareholders, and I am targeting a lower cost of capital and a more flexible debt structure moving forward. We are actively in the market and talking to providers of capital on a refinancing, and I will continue to update the market if and when there are updates available. Okay, to finish the call today, I'll provide a few notes on hedging and our guidance. First, we have a robust hedge policy in place, which looks to balance downside cash flow protection with the opportunity to participate in commodity upside, taking into consideration our lender requirements and capital prospects. On natural gas, we moved from being about 95% hedged in Q4 2025 to about 70% hedged in Q1 2026 and about 65% for calendar 2026 and Q1 2027, still at pretty supportive pricing. These hedges continue to provide substantial cash flow protection. but we are continuously looking to re-hedge volumes if and when the forward market provides us the opportunity of pricing north of $3 a GJ. Speaking of opportunity, we have been active in recent weeks layering on several WTI and power hedges for late 2026 through calendar 2029, as you can see in the chart on the bottom right. We hedge our C5 production against WTI swapped into Canadian dollars. While most of the recent WTI price spike has been in the front months, we've seen the long-term curve move up into a range that we're comfortable with and has allowed us to average up our weighted average pricing. We're about 70% hedged on C5 right now in half one 2026. So we do have some exposure to the very large increase in prices. Power represents over 30% of our total operating expense. So while it doesn't get much external discussion, we have an active physical power hedge book that allows us to de-risk this operating expense, especially as Alberta power prices have softened in recent quarters. Darcy has already discussed sulfur pricing at some length, so I won't add to that, other than by noting that we are open to protecting a portion of our 2027 and beyond sulfur sales if we can get strong prices and are evaluating opportunities with our marketing counterparty. Finally, we're not updating guidance at this time from what we released back in December. To provide a bit more color on our guidance assumptions, we factored in that turnaround in the third quarter of this year, which is a six-week outage at Caroline that will take the facility and all associated owned and third-party volumes down for that period of time. It will cost approximately $15 million net and will be funded by internally generated cash flow. We've also factored in a NOVA pipeline maintenance outage that effectively shuts in our Waterton plant for about 18 days in June. This one came as a bit of a surprise from TC Energy in the fall, but there's nothing we can do about it. I recognize our guidance assumptions are pretty conservative on liquids and sulfur pricing if you compare those assumptions to current spot prices, but these are offset by ACO, which has weakened materially across the curve since we set guidance. We continually evaluate our results and forecasts and will continue to provide quarterly updates if and when we feel guidance needs to be adjusted. That concludes my portion of the call. We're certainly proud of our 2025 results and excited to deliver a strong 26. Thanks to everybody for participating today, and I'll turn the call back over to Dallas for concluding remarks and questions.

Thanks, Adam. I'll now ask the conference coordinator to manage the telephone questions portion of the call, and then I will handle the questions we are getting over the webcast. Go ahead, Kevin.

Thank you. We will now take questions. If you have a question and you are viewing on the webcast, please use the Ask a Question button on the top right-hand corner and type in your question. If you have been participating via telephone, please press star 11 on your telephone keypad. There will be a brief pause while we register participants. Thank you for your patience.

Our first question comes from Adam Gill with Ventum Financial.

Your line is open.

Good morning, gentlemen. Congratulations on a solid quarter. Two questions for me. First off, on the midstream processing revenue, a nice uptick to $12.6 million in the quarter. How sustainable do you see that level of revenue for 2026?

Thanks very much for the question. It's Paul Kunkel here, Chief Commercial Officer. We actually believe that that revenue is very sustainable through 2026 and into 2027. We have the opportunity and currently are working on growing that through the end of the third to fourth quarter of 26 as well. So we believe it's very sustainable.

Okay, great. Second question is just on the sulfur side. Have you made any... attempts to secure some of the higher pricing that we're seeing right now at Vancouver on the remaining one third that's available at spot. And have you used this higher pricing to initiate discussions on locking in pricing for 2027?

Yeah, thanks, Adam. It's Darcy here. Really good questions. Obviously, anytime we see traction in any kind of commodity pricing like we've seen, largely driven by oral events, we try to take advantage of that. We think it's still early days based on the feedback that we're getting. There's still a little bit of trepidation, I would say, as to what the long-term implications are, longer-term implications are on sulfur. But as we addressed in the formal part of the presentation, we're very interested in looking at certainty on a portion of our sulfur production in 27 and 28 years.

Okay, great. That's all for me. Thank you. One moment for our next question. Our next question comes from Joseph Schachter with Circe.

Your line is open.

Good morning, everyone, and congratulations on a good quarter and a good year. First thing, if you did not have the contract that you had in Q4, how much additional revenue would you have received given current pricing environment? Are we looking at a $12, $14 million incremental number if that had been the case in Q4 of 25?

Yeah. Thanks, Joseph. It's Adam here.

I'm just doing a little bit of envelope math, but I see it roughly $13 to $17 million of additional revenue for the first quarter. Of course, that would be offset if we didn't have our gas hedges, we would probably see the same in reverse on bad gas pricing. So sometimes you win on hedging and sometimes you lose. But yeah, certainly that hurts a bit in the first quarter.

And this second question, you know, given, you know, you've got good hedges in through, you know, early 2027 and hopefully from the back half of here, we get better ACO than current prices. the liquids portion is going to generate a lot more cash flow. You could get down to that $100 million debt target in 2026. Am I correct that that's a possibility?

Yeah, I think it's within the realm of possibility. Certainly with the outages we've got in Q2 and Q3, we'll have a little bit less opportunity to aggressively repay debt, but certainly into the fourth quarter, we'll get back to doing that. But, yeah, I could see us getting very close to our one times EBITDA target by the end of this year or early next year, and then happy to talk about capital allocation after that point.

Yeah. So, going to that, you know, question of capital allocation, you know, Q4 2027, is the goal bring on more of the natural gas that's shut in? Are you looking at drilling some new wells, which could be higher sulfur content? Can you give us some of the things that you'd be thinking about for capital allocation, including even return on capital, i.e. dividends or whatever?

Yeah, thanks, Joseph. Darcy here again. We absolutely are thinking about all of those opportunities in terms of capital allocation. We are very focused in the shorter term on debt reduction, but your question was sort of focused on the back half of 2027, if I heard you correctly there. We think, first of all, there's a lot of low-hanging fruit within the company in terms of optimization projects and smaller capital projects. The Shell assets in particular, which is the majority of our core assets, were very under invested by Shell prior to our acquisition of them in 2019. And since that time, we've been very focused on debt reduction and the use of any free cash we've been putting towards debt reduction, doing maintenance turnarounds and things like that. So we've really underfunded the investment opportunities on these assets for quite a period of time, call it a decade even. And so there's a lot of low hanging fruit that we'd like to immediately put our free cash into once we get our debt to EBITDA ratio into a good place. Beyond that, we obviously are looking at replenishing our resource. A couple different ways to do that. Obviously drilling it, obviously acquiring things. We'd like to look at accretive acquisition opportunities that contain some development drilling upside associated with them. But we see that as being a two to three year timeframe at this point. We would like to see sustained ACO gas prices that are $3 per gigajoule or better. Even though the value of sulfur can potentially offset some of the requirement for having strong gas prices, we'd like to see $3 gas before we really commit to putting money into the drill bit.

Super. Last one for me. Given you have still some uncontracted with shell of the sulfur, are you getting approached by desperate fertilizer users to maybe sell directly to them? And is there a price difference between that and the Vancouver price?

Our buyer and the contract that we have with our buyer dictates Vancouver pricing. The information that we have is suggesting that geopolitical events are probably providing some tailwinds in Middle Eastern and Asian markets around sulfur. We have not seen that translate yet to Vancouver pricing. We are cautiously optimistic that it probably will over time. We're focused on Vancouver pricing because that's the contractual arrangement that we have through to the end of 2029 if our buyer exercises their option year. Does that answer your question, Joseph?

Yeah, super. I just wondered if there was a slice that wasn't under contract provisions, but that explains it. Thanks very much, guys, and again, congratulations on a good year, and the market reaction has been quite good over the last number of months.

Absolutely. Thank you. Thanks, Joseph.

Thank you. There are no further questions at this time. I'd like to turn the call back over to Mr. McCollum to manage the webcast question and answer portion of the call.

Thank you, Kevin. We do have a number of questions that are coming in, so I'll read the question and then one of my colleagues will respond. First question is, we've covered some of it, but it's related to the Sulfur Marketing Agreement. The Master Sulfur Marketing Agreement runs to Q4 2028. We would like to understand the relationship between that agreement and the 2026 structured pricing. Is the three-year, the three tranche structure, fixed, collared, and spot a subset of the master agreement? And what happens to the two-thirds of non-spot volumes in 2027? Paul?

Yeah, thanks, Darcy. Yes, the 2026 agreement is what I would call an amendment to the master agreement, as you put it. And this agreement or amendment is with the same marketer as our long-term agreement. And in 2027... In 2027, we're under that so-called master agreement as well. And as you talked about before, we would seek opportunities through that marketer to potentially fix some of the pricing and evaluate the likelihood and then the approach in fixing that pricing.

Okay. Next question is our understanding that sulfur throughput constraints at CAVI are primarily at the reservoir level, not at the SRU or facility level, meaning that you have meaningful excess midstream capacity to grow sulfur production without significant infrastructure capital investment. At what level of balance sheet deleveraging does management get comfortable initiating a drilling program or pursuing acquisitions of additional sour gas?

I can maybe take that one. It's Darcy here. There's a lot to unpack in that one, so hopefully I can remember all of the questions. Maybe the second part first. I think I answered most of that question in my response to Joseph's question. Our immediate near-term priorities are debt retirement, and then we'll be looking at deploying free cash back into the business, some of the low-hanging fruit opportunities that I mentioned. And then we'd like to see drilling occur under the guise of $3 per GJ plus natural gas price. Obviously, depending a little bit on where sulfur pricing is and what targets we're drilling because there's different hydrogen sulfide and sulfur contents in those targets. The first part of the question related to sulfur recovery Yes, sulfur recovery is directly proportionate to the hydrogen sulfide content in the feedstock to the gas plant or the gas plant in gas plants in aggregate. As I mentioned in my formal part of the presentation, we do have significant excess capacity. It varies a bit between the three gas processing facilities, the Caroline facility being the most full, but we still do have 15 to 20% excess that we can fill up that gas plant with. We also have opportunities to invest in de-bottlenecking and even expansion opportunities if there's enough commitment of either third party volumes or our own volumes that need plant processing capacity. So we really don't see that there's a realistic or obvious limitation to sulfur recovery at this point. Now one thing to keep in mind is a lot of the drilling activity that's happening, particularly around our Caroline gas facilities, the drilling activity is centered on sweet gas reservoirs. So there is no H2S in the production and therefore there's no sulfur recovery that comes from that. And that drilling is being carried out right now by some of our current customers that process gas through our facility.

Great, next question. The MD&A notes that Caroline is approaching nameplate capacity with 64% third-party utilization in Q4, and that the bottlenecking opportunities are under evaluation. Would these projects be incremental to the 35 to 40 million 2026 capital guidance, or is it already captured within it?

John Emery, COO, there is no Caroline de Bottlenecking capital currently in our 2026 capital guidance. The Caroline gas plant existing infrastructure supports multiple expansion paths that we're evaluating against the projected demand. It's too early to provide a capital estimate for de Bottlenecking without confirming what that demand is going to be. That said, any expansion at Caroline will cost far less than greenfield or new construction. That's about all I can say.

Thanks, John. Next question. Regarding the permanent shutdown of the nearby third-party processing facility in the vicinity of Jumping Pound and the resulting volume redirect beginning in January 2026, can management give any indication of the expected annual incremental processing revenue contribution from this redirect?

Thanks, Alice. Paul here. The redirect will provide us with roughly $3 million in additional processing and handling fees per year, which equates to about $250,000 per month, and will also provide efficiencies in both GHG and per unit operating costs to the facility.

Thank you. In your latest corporate presentation, you list diversifying acquisitions as one of your objectives for 2026. Can you please elaborate on the kinds of acquisitions you are considering? And are you considering tuck-in acquisitions that would add low-decline, mature sour production in the foothills region with the goal of generating a step change in your sulfur production?

Maybe I can take that one. We're looking at acquisitions first and foremost that would be accretive to our operating and financial parameters, but we also think that any acquisition that we entertain doing also has to have some follow-on development activity Tuck-in acquisitions or nearby acquisitions are obviously going to be things that we look at. We'd love to consolidate our current core area positions. I'm looking for the question there again, Del. Sorry, it moved on me. It's right there. Yeah, thank you. I think I answered it.

Yeah, I think you're good. Yeah, we'll move on. When you return to the growth via the drill bit, which of your core areas present the locations with the most competitive return profiles?

Yeah, the most competitive returns on a risk basis would certainly be in our Waterton area. Those are quite expensive. wells. We're looking at somewhere between $12 and $15 million for drilling location for drill equipment tie-in, but they also generate some of the best returns. We're highly interested in drilling in Waterton. Waterton would almost exclusively be sour gas development as well, so we also get the additional torque because of the hydrogen sulfide content and ultimately sulfur recovery that we would get out of those wells.

Next question. What is the probability of achieving sulfur production capacity of 1,500 tons per day in 2026? And what are the key determining factors?

Yeah, I think that's a fairly straightforward answer. So our guidance of 1,000 to 1,150 metric tons per day of sulfur assumes that the currently shut-in production in central Alberta that goes into a third-party facility remains shut-in for the entire 2026 calendar year. In the event that that can return to production, there's about 300 metric tons per day associated with that. So if you add those two numbers together, obviously, we're very close to 1500 metric tons per day of sulfur right there. And that's without any further deployment of capital or resource development. Obviously, additional investment into hydrogen sulfide bearing raw gas production could contribute to ultimate sulfur production.

Great. Next question. What is the outlook for eco-natural gas price over the next couple of years, Paul? Thanks, Dallas.

Tough question to answer, but I think our view would be that eco-gas prices would likely remain undervalued, or as Darcy put it earlier, stubbornly low over the next six to 12 months. We're certainly hopeful appreciation over the next 12 to 24 months, though.

Great. Next question. With the $27 million USD repayment completed in Q1 against debt, your net debt is likely near your target today. Can you please confirm the current debt level and why a buyback is being launched immediately to support the share price?

Yeah, it's Adam. I'll take that question. Our debt today is approximately $125 billion CAD. I would say we still have room to go. Certainly, commodity price businesses are volatile. And then as it relates to share buyback, as I think both Darcy and I mentioned, we have a very long list of capital deployment opportunities within our asset base. We've generated, as I said, 147% return on the small amount of capital we've been able to deploy. I think we can and we will provide better returns to our shareholders by starting to deploy that capital into our business, growing our business, than we can by a dividend or share buyback, at least in the next few years. So that's certainly our plan at the moment. And we'll keep reevaluating those capital allocation decisions as the world changes here.

Thanks, Adam. That's all I have for questions. Great. I would like to thank everyone for participating today. We very much appreciate your time and your interest in CAVI. If you have any further questions, please call us at 403-261-5900 or email us at investors at cavienergy.com. Thanks again, and we look forward to speaking with you soon. Thank you. This conference call has now ended.

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