Cavvy Energy Ltd.

Good day, ladies and gentlemen, and welcome to the CABI Energy Third Quarter 2025 Financial Results Conference Call. Please be advised that today's proceedings are being recorded. Following the presentation, we will conduct a question and answer session. If you have a question and you're viewing on the webcast, please use the Ask a Question button in the top right-hand corner to type your question at any time during the presentation. If you are participating via telephone, and would like to ask a question, please dial star 11 at any time. You will then be in the queue for the question and answer session at the end of the call. I would now like to turn the meeting over to Mr. Dallas McConnell, Vice President, Corporate Finance. Please go ahead, Mr. McConnell.

Thanks very much, Daniel, and good morning, everyone. I would like to welcome you to CAVI Energy's third quarter 2025 conference call. With me today are our 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 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 the Canadian Cert Securities Regulators on cdarplus.ca. With that, I will now turn the call over to our President and CEO, Darcy, who will provide more detail on our performance last quarter, along with recent corporate developments.

Thank you, Dallas, and thank you everyone for your interest in CAVI Energy and in our third quarter 2025 results. I'm extremely pleased with our solid performance in the quarter. The ongoing focus on successful execution of our strategic plan continues to bear fruit, even with the additional pressure of an oppressively low natural gas price in the quarter. I'm also very excited to share the details of a new sulfur sales forward pricing agreement for 2026, which was disclosed in our news release after the close of markets yesterday. We believe this pricing agreement materially reduces revenue risks for the company in 2026, providing even greater certainty towards meeting our strategic objectives, most notably debt reduction. Before we get to that, however, I'd like to take a brief moment to remind everyone of the compelling reasons to invest in CaviEnergies. CAVI's low-decline production capability of 33,000 BOE per day, consisting of approximately 85% natural gas when our shut-in dry gas is included, is supported by extensive owned infrastructure, highlighted by our three operated natural gas processing facilities that have both deep-cut natural gas liquids and sulfur recovery. These processing plants have almost a half BCF per day of raw gas processing capacity in aggregate, with the ability to accommodate CAVI volume growth, regional facility consolidation, and custom processing of third-party raw natural gas production. We've achieved tremendous success lowering our operating cost structure and growing our third-party processing business by taking advantage of the opportunities created by our extensive infrastructure ownership. With the deep expertise and track record of our management team and board of directors and our highly supportive major shareholder, we are poised to deliver and anticipate additional success as we maintain focus on the execution of our strategic plan. Calendar year 2025 has been a year of transition where we have completed our strategic pivot to focus on improving the cost structure and efficiency of the business, growing our gathering and processing business, repaying our debt, and preparing for significant cash flow improvement with the year-end expiry of our current fixed price sulfur contract. We have entrenched a new culture of resiliency, innovation, high performance, and excellence in our organization. I'd like to refer to everything we have accomplished to date as our first phase of our strategic plan. As we transition to our second phase, We will continue to maintain a mindset of continuous improvement on our accomplishments to date. We are excited to begin implementing phase two of our strategic plan in 2026. Phase two will see a notable emphasis on accelerating deleveraging and positioning CAVI for sustaining and ultimately growing our asset base with the objective of driving growth in per share value and investor returns. In phase two, we anticipate firming up plans for replenishing and growing our asset base through our extensive drilling inventory of over 300 identified locations and by identifying potential acquisition targets. We look forward to sharing more information with our investors as we further advance our phase two strategy. We're also pleased to have recently participated as a presenter at an industry investor conference in Calgary, where I had the opportunity to tell our story to a standing room only audience. We are looking for more opportunities like this, and I'd be thrilled to meet those interested in our story at these events. We are proud of our accomplishments so far, but much work remains. We are excited about the opportunities ahead, and I look forward to connecting with existing and new investors in the future. Getting back to the immediate matters at hand, I'd like to now focus on our accomplishments in the third quarter. Overall, our original expectations were for a relatively soft third quarter with seasonally weak natural gas prices reigning in our expectations. Overall, however, we are pleased with a solid quarter that showed ongoing improvements in our business, including growth in our raw gas processing business, higher gas plant utilization, lower costs and improving netbacks as a result. Net operating income of nearly $31 million was strongly supported by commodity hedging gains of nearly $28 million in the quarter. This was largely on the basis of our 110,000 gigajoules per day of gas sales hedged at $3.32 per gigajoule, offsetting an average unhedged realized ACO gas price in the quarter, of a paltry 65 cents per gigajoule. Production of just under 24,000 BOE per day reflected the ongoing shut-in of wells in west-central Alberta, northern Alberta, and northeast British Columbia, representing an aggregate shut-in volume of approximately 9,500 BOE per day. This 9,500 BOE per day is dry gas producing to third-party-owned and operated processing facilities with high operating costs. CAVI is obligated to pay third-party processing fees on the vast majority of this production, with the corresponding processing fees reflective of these high operating costs. Most of this volume has been shut in since approximately mid-2024, with the northern Alberta and northeast BC volumes producing sporadically since that time, but they remain shut in today. We are currently evaluating the restart of Northeast BC production since sustained gas prices of just under $2 per gigajoule may prompt us to do so. However, the high cost structure at the third-party facilities makes the restart of the West Central and Northern Alberta volumes highly unlikely until at least the end of calendar 2026. Processed raw third-party gas volumes averaged 136 million cubic feet per day in the quarter, representing a 105% increase in volume and an 87% increase in revenue as compared to the same quarter in 2024. I'll speak to the continued growth of our processing business in a minute, but this growth is only possible because of our ownership in our three major industrial sites at Waterton, Jumping Pound, and Carolines. We believe these sites will continue providing opportunities to grow our processing business while having the potential to accommodate new energy-based opportunities in the mid and long term. In our last quarterly results call, we suggested that our full year 2025 net operating income guidance was anticipated to be closer to the high end of our guidance range. Given our continued strong results, We have increased our net operating income and net back guidance for 2025, and Adam will provide a few details on this revised guidance in a few moments. And for my last highlight, I am very excited about our new 2026 sulfur pricing agreement. We executed this agreement subsequent to the end of the third quarter, and I'll provide a few details at the conclusion of the next slide, which updates our ongoing success in growing our third-party processing business. I'd like to direct your attention now towards the chart in the upper left and the chart in the lower right of this slide, because these really speak to the growth in our third party raw gas processing. The chart in the upper left shows the improvement in the revenue derived from third party volumes. We have increased revenue in each of the last five quarters, culminating in revenue exceeding $10 million in the third quarter of this year. On a full-year 2025 basis, this third-party derived revenue is anticipated to contribute over 15% of the company's total revenue, so it has become and will remain an important revenue source into the future. The chart in the lower right provides a similar view, but on the basis of raw gas volume rather than revenue, and shows additional detail by illustrating the volumes processed at each of our three primary facilities, again showing growth over five consecutive quarters. This chart also shows that our Caroline gas plant handled approximately 60% of the third-party volume in the third quarter, while our jumping pound facility handled about one-third. We will continue providing updates on this part of our business in future quarters, since it remains a cornerstone of our strategic objectives. As we move to my last discussion item before I hand the floor to Adam, I want to take a moment to refresh a key message that we've communicated several times in previous quarterly results discussions and conference calls. CABI's unique asset base means that we are a significant producer of elemental sulfur, with sulfur derived from the extraction and conversion of the hydrogen sulfide present in the raw gas resource that is in place throughout much of our geological asset base. Since CAVI's purchase of the Waterton Jumping Pound and Caroline assets in 2019, the company has been contractually obligated to sell up to 90% of our recovered sulfur to a third party at a realized price of six Canadian dollars per metric ton. This contract reaches the end of its term and fully expires on December 31st, 2025, which is now less than two calendar months away. Similar to crude oil, natural gas, and other commodities, sulfur pricing can at times be volatile and sometimes highly so. The chart in the lower right of this slide is one we have often shown And it illustrates this sulfur price volatility over the past 15 years since 2010. One of the most recent examples of volatility occurred in 2022, precipitated by the Russian invasion of Ukraine and the subsequent pricing volatility, similar to many other traded commodities. Sulfur pricing spiked to approximately 500 US dollars per metric ton. only to crash very quickly by 2023 to less than US$100 per metric ton. Because a true hedging market for sulfur is not available as it exists for the primary hydrocarbon commodities, we've been investigating options for some time now that could help manage the risk of this volatility within the context of what remains a highly attractive upside revenue opportunity when our current sulfur sales contract expires on December 31st. We are very excited that our work has culminated in this week's execution of a forward sulfur pricing agreement effective January 1st, 2026 for the calendar year 2026. Under the terms of this agreement, our counterparty will purchase one-third of our sulfur sales at a fixed price of $225 per metric ton, and one-third within a collared structure, with a floor of $205 per metric ton, and a cap of $250 per metric ton. The remaining one-third of sulfur sales will fetch the Vancouver FOB spot market price, which is currently approximately $315 per metric ton. These prices are subject to the customary deductions for transportation and marketing, which are conservatively estimated at $70 per metric ton. We expect to incur additional operating expense related to sulfur processing and forming of approximately $10 per metric ton, bringing our expected break-even cost on sulfur sales to approximately $80 per metric ton in aggregate. It is noteworthy that this one-year structured price agreement provides sulfur sales pricing substantially higher than the FOB Vancouver 15-year historical average of US$135 per metric ton. The pricing agreement will provide substantial protection from pricing volatility and therefore material cash flow protection in 2026, while preserving the ability to meaningfully participate in the spot sulfur market. This price certainty will assist significantly in our operational plans and debt reduction goals. Our operational plans in 2026 include a planned maintenance turnaround at the Caroline Gas Plant in the third quarter. Referencing now the matrix in the lower left of this slide, we have illustrated the one-year sulfur sales revenue generated under the terms of this agreement at various combinations of FOB Vancouver spot pricing and company sulfur production. As an illustrative example, in the third quarter of 2025, the company produced 1,120 metric tons per day of sulfur, the majority of which received the contractual realized price of six Canadian dollars per metric ton. Under the terms of this agreement and effective January 1st, our sulfur sales, when the FOB Vancouver spot price is $300 US per metric ton, would generate approximately $76 million of after royalty net revenue. At the current sulfur contract rates, This sulfur production generates approximately $10 million of after-royalty revenue. The obvious conclusion in this illustrative example is that, under these assumptions of FOB Vancouver spot pricing, approximately $66 million incremental of after-royalty net revenue will be generated in one year under the new contractual agreement. At larger sulfur sales volumes, in line with the company's full capability of approximately 1,500 metric tons per day of sulfur, the matrix illustrates that potential exists for even larger increments of revenue from our sulfur sales. We are extremely pleased with the positive impacts this agreement will generate for our business in 2026 and beyond, and I am confident the matrix and the example I have walked through provides the required insight, but we are happy to answer questions at the end of this call if additional clarity is desired. At this time, I would like to invite Adam Gray, Chief Financial Officer, to elaborate on our third quarter operating and financial results and provide a few details on our debt, liquidity, current commodity hedge position, and our updated corporate guidance.

Thanks, Darcy, and good morning, everybody. Thanks for joining us. Considering the Q3 average basis price for ACO was only $0.65 and we're still just under two months away from our sulfur contract expiring, I'm very pleased with the results for the quarter. As I did last call, I'll categorize our results into three themes. First, consistent, reliable operations in our core strategic operating areas. Second, the continued acceleration of our third-party processing business. And third, continued deleveraging. So on the first theme, I'll turn your attention to the line graph at the lower left of this slide, showing production by area over the last 12 months. During the third quarter, we produced just under 24,000 BOEs per day, approximately 80% of which was natural gas, 10% natural gas liquids, and 10% condensate. Production was essentially flat compared to the same quarter last year, and a little lower than last quarter. primarily as a result of our decision to cycle off our Northeast BC production at the end of Q2, as prices fell over the summer months. As well, we conducted several minor field facility outages through the quarter, as we did seasonal maintenance work, debodimenting projects, and overhauls. As I've previously discussed, both our Northeast BC and Northern Alberta areas produce quite dry gas, which is our marginal production, so we consider it unhedged. These areas also have high variable cost profiles because we don't own very much processing infrastructure up there. We calculate our Northeast BC production breakeven to be just over 80, sorry, $1.85 per gigajoule. So I expect to bring that field back onto production shortly, which will add just over 800 BOEs today. In the last week or so, spot ACO prices have recovered to around that $1.85 breakeven level. and our Q4 ACO spot is sitting at around $2.47 per gigajoule. The remaining shut-in production, both in our northern Alberta sour and in west central, have higher breakeven costs and more complex processing arrangements. So, as Darcy mentioned, we do not have plans currently to return those areas to production. Certainly, the vast majority of our cash flows are derived from our three deep cut sour gas processing facilities, Not only is our owned production which flows into these facilities more liquids-rich than the non-core areas, the infrastructure allows us to process our own gas, produce elemental sulfur, and offer processing services to our customers. Looking forward, we consider these facilities strategic, logistically well-connected industrial centers, and we will continue to seek opportunities to utilize their large footprints to diversify our revenue streams. Darcy has spoken at length about CAVI's success over the past couple years growing this portion of our business. As of Q3, third-party gas comprises 42% of the total inlet volumes across our three facilities, compared to under 30% during Q3 2024. The revenue earned from processing fees contributed $10.4 million in cash flow this quarter, corresponding to $5.18 per BOE on a net back basis. At Caroline specifically, CAVI's own production represents only 30% of inlet gas during Q3. Not only do processing fees diversify and reduce the volatility of our revenue, the corresponding increase in facility throughput has allowed us to reduce fuel gas burned and increase process optimization, both of which contribute to more efficient plant operations. Turning to operating expense now, on an aggregate basis, OpEx was $36.7 million during the third quarter, our lowest figure on record. That's versus $40 million in Q2 of this year and $38 million in Q3 of last year. Our operating costs are comprised of roughly one-third electricity costs, one-third people costs, and the remaining one-third a combination of various other cost types, including maintenance, chemicals, regulatory fees, et cetera. The biggest driver of our reduced operating expenses on a year-to-date basis remain lower processing fees paid as a result of the shutting of our uneconomic production, but we have also contributed to lowering the cost burden of our own operations through continued efficiency gains and carbon tax reductions. On carbon taxes, this quarter benefited from lower carbon intensity as a result of higher throughputs, a favorable change to the tier government policy, as well as our continued access to deeply discounted carbon credits available on the market. $36.7 million of OPEX translates to $16.64 per BOE for the quarter. As you know, we also calculate adjusted operating expense to help demonstrate that operating expense is incurred to process all the throughput molecules in our facilities, not just our own hydrocarbons. We do so by deducting third-party revenue and sulfur revenue from our operating expense. In Q3, adjusted operating expense was $10.31 per BOE, another record low versus $11.58 last quarter and $14.91 in Q3 of 2024. Okay, turning to financial results. We're pleased to have generated $30.6 million in NOI, or $0.11 per share, which contributed to $11.9 million, or $0.04 per share, in fund flow, as Darcy mentioned. We posted positive NOI and net back on an unhedged basis, but certainly recognized the strength of our gas hedge book, which continued to deliver stability on gas and also condensate revenues. Realized hedge gains were $27 million in aggregate for the quarter, or $12.50 per BOE. Capital expenditures remained relatively constrained in Q3, reflecting our desire to conserve cash and repay debt. However, we've continued to invest in high-impact well and facility optimization projects financed by our rights offering last fall. We have invested over $8 million into this optimization program since late 2024 and have realized significantly over 100% aggregate return on investment from those investments year to date. While the capital pool available for this program is relatively small, its ongoing deployment will continue to positively impact cash flow over the short and long term and meaningfully improve our business valuation metrics. Now to touch on our third and final theme for the quarter, we're pleased to have put up another quarter of net debt reduction, being the fifth quarter in a row, aggregating to total reduction of $55 million over that time. External debt actually increased about 1.5 million USD this quarter as a result of a small net revolver draw and the FX rate moving against us a little bit, which increased the CAD value of our US denominated debt by just over 3 million. These are offset by a continued reduction in our non-cash working capital deficit to a record low of 10.6 million at September 30th. And additionally, we've paid another US $1 million against the revolvers subsequent to the end of the quarter. We could have been more aggressive with debt reduction this quarter, but instead chose to continue some capital allocation into optimization projects while looking forward to accelerated deleveraging into 2026 on the basis of the SOLFR contract that Darcy's discussed. Additionally, we took a short Waterton facility outage through the first three weeks of October this year, in order to conduct a preventative maintenance operation while market prices remain muted. As a result, we did preserve some liquidity on the balance sheet at September 30th. Okay, finally, I'll finish up my section of the call this morning by touching on our hedge position and 2025 guidance update. In aggregate, our natural gas production was 95% hedged this quarter, representing 110,000 GJs per day at a price of 332 per GJ. That 110,000 GJ hedge level will continue through the remainder of 2025, then drop to 78,000 GJs per day in Q1 2026, following through the year to 63,000 GJs by Q4 2026 into Q1 2027. We expect and hope to be able to layer in some additional cash gas hedges for 2026 and 2027, provided forward ACO pricing supports us doing so at or above that approximately 3.32 per GJ annual average pricing level. Our condensate production was approximately 66% hedged during the quarter. Those hedges, which are a combination of callers and swaps over the next 30 months, gradually decline from 1,600 barrels a day now to roughly 1,200 barrels a day through calendar 2027 with a smaller position in place through Q2 2028. 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 forward capital plans. On the currency front, we had previously hedged the majority of our USD denominated debt service obligations during 2025 and the first half of 2026. However, because the new 2026 SOLFR contract settled in US dollars, we plan to reconsider our currency hedge program moving forward, as we will be naturally hedged between SOLFR revenues incoming and USD debt interest and principal payments outgoing. Finishing with a guidance update, the business continues to perform better than initially expected on most cash flow metrics. As a result, we've increased our NOI and net back guidance to a range of 100 to 110 million and 1150 to 1250 per VOE, respectively. In a year where revenues are largely hedged and capital is deeply constrained, the guidance range increase is a testament to the value of our third-party business as well as our efforts to reduce operating costs. We continue to see some positive upside potential should ACO prices recover as we move into Q4. Finally, I expect participants are eager to hear some discussion of our 2026 guidance. We will announce 2026 guidance in early December following the approval of our 2026 budget, at which time I will be able to provide some commentary on our plans for the year. That concludes my portion of the discussion. Thanks to everybody for participating today, and I will turn the call back over to Dallas for concluding remarks and any questions we might have.

Thanks, Adam and Darcy. I'll now ask the conference coordinator to manage the telephone question and answer portion of our call.

Thank you. We will now take questions. If you have a question and you're reviewing on webcast, please use the Ask a question button in the top right-hand corner to type your question. If you have a question and you're participating via telephone, please press star 1-1 on your telephone keypad. There will be a brief pause while the participants register. Thank you for your patience. We do have a question over the telephone from Yosef Schachter with SER. Your line is open.

Good morning, Darcy and Adam and the rest of the team. The first question for me is you mentioned in your commentary that, of course, sulfur production can come up with the sour gas coming back on. And you mentioned, you know, where it might come on and when it go in stages. What price do you need for that gas to come on? Is it, you know, this $2 number or do you prefer a three or, you know, wait another couple of months to see if the ACO number goes from you know, the two to the three, and then what kind of volumes, you know, could come on in 2026 on top of what you got, knowing that, you know, you have capacity, you know, for 35,000.

Hi, Joseph. It's Darcy here. Thank you for your question. You tailed off a little bit at the very end, but I think we got the primary gist of what you were asking there. From a sulfur production, sulfur sales perspective, The vast majority of remaining sulfur production potential is associated with our west central area volumes, and we do not see those volumes coming on stream until at least the end of 2026, per my remarks in the formal portion of the presentation. Unfortunately, that production is dedicated through a contractual arrangement to the end of 2027 calendar year, and the cost structure associated with the facility that that produces into is extremely high, and there's really almost no gas price or combination of gas price and sulfur price that will allow that production to resume in the foreseeable future. Of course, if things were to change in that regard, we're always on top of that, and we will make a different decision when and if the economics are sustainable. But we see that not happening until at least the end of 2026, if not beyond.

Super. Our next question is, of course, you know, you've talked about Carolina jumping pond and all the big changes there. Is there much upside in the Waterton area, you know, from volumes and, you know, you mentioned there's some maintenance issues going on. What could be the torque on the upside from there into 2026?

Yeah, again, I think I can answer that question, Joseph. First of all, I would maybe clarify that there isn't any maintenance issues at Waterton. The outage that Adam referred to was a proactive outage to address some preventative maintenance items that we had to deal with. And our thought process was we could either deal with it now during a low priced environment, or we could deal with it in 2026 during a higher priced environment. So we chose to do that now. As far as the sustainability or the upside potential in that Waterton area, we own and control the vast majority of what the productive, what we believe the productive mineral rights opportunities are in that area. And therefore it really boils down to our ability and our decision making around when to deploy capital in that area to develop resources. We have a tremendous amount of resource undeveloped resource potential in that area. The cost to drill down there is quite high. The per well cost is extremely high. But the reward is commensurate with that cost. So as we look forward into our strategic execution under phase two in the years following the current year, we're excited to look at drilling opportunities and the timing of that will be subject to a future decision.

Okay. Next one for me is, of course, funds flow. You know, given what you've done this year, and, you know, a better, you know, Q4, you probably have 60 million of funds flow this year. And then you add in, you know, the sulfur opportunity, that could mean another 60 million next year. So 120 million, and with 291 million shares, we're talking, you know, 40 cents plus in funds flow next year. Where do you want the debt to go? Like, you know, you know, if you have 120 million of funds flow and your net debt right now is the 164. Are you going for a goal of one times to cash flow and then look at other alternatives at the board level for growth versus shareholder returns?

Yeah, again, maybe I'll start the answer and then I'll pass it over to Adam and you can kind of get his financial take on things. But generally, the answer would be we are very motivated to deleverage and get our debt level down. So we're going to be directing large proportion of any funds flow towards debt. Our target really, we kind of joke about this, but our target really is having no debt. The reality of it is we always want to leverage a little bit of debt into our business plan So, you know, as far as a ratio goes, certainly lower than what it is today, certainly lower than one, ideally, but probably not zero. But go ahead, Adam, and provide some elaboration, if you will.

Yeah, I think that's right, Darcy. A 1x debt to cash flow is a good start. I think that allows us to look at doing a refi. late next year, midnight late next year, that could put us into a much more flexible debt structure that could allow us, you know, potentially a larger revolver to draw when we wanted to and to repay when we wanted to. Because these three facilities do require these large capital maintenance activities once every approximately five years, there is sort of an embedded debt structure in our system. in our business that we think of those big capital turnarounds as debt. So probably the optimal debt level going forward is a little lower than maybe some of our peers.

Super. Well, thank you very much for answering my questions and congratulations on signing the software deals. I think that's going to really wake the story up in 2026. Thank you very much.

Thank you, Joseph. Thanks, Joseph. Thank you. There are no further telephone questions at this time. I would now like to turn it back over to Mr. McConnell to manage the webcast question and answer portion of the call.

Thank you, Daniel. We do have several questions coming in through the webcast, so I will direct them. I think we're going to be able to get everyone on the team involved in answering these, some of which have been addressed already in previous questions, so I will just skip over those ones. First of all, a valuation question. Your stock still trades at roughly half of peers on an EV to cash flow multiple, despite consistent execution. Beyond the results themselves, what concrete steps are you taking to improve market visibility and help close the valuation gap?

Yeah, it's a great question. I addressed part of that answer, I believe, in my formal part of the presentation. We conscientiously waited until this year to really hit the ground running with respect to getting our story out there. We wanted to ensure that we had a very clear, concise strategic plan that we could lay out. We wanted to make sure that we had some actual results coming in the door that we could point to that proved up, that our strategy was sound and effective. And as we came into 2025, we felt that the time was right to start marketing our story much more actively than we've done in the past. So we've been doing a tremendous amount of outreach to various investment bankers and brokers and other folks who can help us to develop our story and get our word out there. As I mentioned in my formal comments, we're looking for more opportunities to do that in the future. And again, I think as the who asked the question pointed out, we're actually showing some consistent value generation results at this point in time. So, we're hopeful that we're going to start to be able to gain and retain higher interest than we have in the past because of that information that's coming out.

All right. Next, with respect to sulfur transport and pricing, we did address this earlier in the presentation, but I think it probably doesn't hurt to hit it again. Can you clarify what transport and handling deductions typically run per ton and whether those costs are expected to change under the new 2026 sulfur pricing structure?

So currently, the forming, transportation, and handling deductions are $80 US. Under this new agreement, we don't anticipate any material changes to those pricing structures at all, although there is some variability with regards to transportation over time. We don't expect anything material to change.

Sulfur capacity expansion. Now that we've secured the 2026 sulfur contract, are there plans or opportunities to expand sulfur recovery capacity beyond the 1,300 to 1,400 tons per day?

Yeah, I can take that, Darcy, here again. I think the question is really about what's the opportunity to grow the sulfur recovery as opposed to the sulfur recovery capacity. We have plenty of sulfur recovery capacity in our facilities. Really, the amount of sulfur recovery, the amount of sulfur volume is directly proportionate to the amount of sour gas production that comes into the facilities. And as we continue to look for opportunities to consolidate facilities, we will be able to bring additional sour gas into our facilities. Of course, it depends on whether that's CAVI-owned gas or if it's third-party-owned gas. Third parties producing into our facilities will typically be taking their own sulfur in kind and marketing that sulfur. Our growth will have to come through either reactivating the existing sour gas production that's shut in right now, which we believe will happen as we approach the end of that contract dedication that I referred to earlier for the volumes that are tied to the third-party facility in West Central Alberta. In addition to that, growth of our production volume through investment in either the drill bit and or through acquisition will provide us with additional sulfur production and recovery over time.

Next, would management consider publishing more detailed sulfur margin or cost per ton disclosure in future MD&A to help analysts and investors model the uplift more accurately?

Yeah, I think that the short answer to that question is yes. Certainly, the expiry of the old $6 per ton sulfur contract changes our business results. And I think it's reasonable to expect our MD&A and external documents to reflect some changes so that we ensure our investors better understand how cash flows move. So stay tuned for that.

Next on upstream drilling, can you speak to the nature of potential future drilling going forward? Would they be near your existing gas plants and therefore processed by them? would they also target NGLs and condensate?

Yeah, I can probably answer that. We have that extensive 300 plus identified drilling locations in our inventory, as I mentioned in the formal part of the presentation. Of course, economics and return on investment will always drive our decisions with respect to what drilling targets we pursue. Obviously, if we can drill targets that are close to existing gas gathering infrastructure, The cost of tying in the developed volumes will be lower, which improves the economics. Of course, we're highly motivated to drill production that would ultimately feed our processing facilities. The incremental or marginal cost associated with bringing additional owned volumes into our facilities is extremely small, which again helps the economics. So ideally, yes, we're targeting locations that are near our infrastructure and will be processed at our infrastructure. That does not preclude that we will, you know, look at comparative economics across our entire portfolio and we'll always choose the best combination of economics and risk management. With respect to the second part of the question, would they target NGLs and condensate? Of course, with the fairly robust pricing on liquids, natural gas liquids, over the past several years, particularly in comparison to natural gas pricing. Any liquids-rich opportunities are generally driving better economics, at least historically, than dry gas opportunities. Having said that, everybody knows that the crude oil and the associated liquids markets have taken a bit of a kick here in the last couple of months in particular. At the same time, I think there's a general bullishness towards future gas pricing, and maybe that equation is changing a little bit and there will be a more balanced view of the value of gas versus the value of liquid. So stay tuned. I think that those decisions remain to be made based on what forward pricing looks like.

Thanks, Darcy. Here's a good one for Paul. I'd like to know whether the company is actively seeking partners in the AI data center space. or if we are simply waiting for opportunities to arise?

We have a very robust pipeline of opportunities in both the power plant and data center space. Those opportunities range from initial discussions to project-specific discussions, and we're working very hard to bring forward a definitive agreement in the near term. Thanks, Paul.

A lot of great questions. Really appreciate the interest. Obviously, you folks have been paying a lot of attention, so really good questions. Thanks for everyone for participating today. We very much appreciate your interest in CAVI. If you do have further questions, you can call us at 403-261-5900 or email investors at cavienergy.com. Thanks again for your time today and your interest. We look forward to speaking to you soon. Thank you. That will be the end of the conference call. Please disconnect your lines at this time. Thanks for your participation.

Thank you. The conference call is now ended. Please disconnect your line at this time. Thank you for your participation.