Tenaz Energy Aktie

Hello. I'm Tony Marino, President and CEO of Tenaz. Thank you for joining our Q2 '26 update. At the outset, I'd like you to note our advisories that we have at the beginning and the end of this presentation.

Let's start with our operating and financial results. Production was up again in Q2, 6% higher than in Q1, reaching over 17,000 boe/d. And I will point out that our preliminary production that we have for July is approximately 23,000 boe/d. So continued organic growth in Tenaz as a result of the development activities that we and our operating partners are conducting on our assets, primarily in Netherlands.

Funds flow from operations, $74 million. That's a 15% increase from Q1 on higher pricing and higher production. The better pricing, in particular, is reflected in our operating netback, which has reached over CAD 69 per BOE. That's a 20% increase from Q1 '26 operating netback. CapEx was significantly lower than in Q1. The total for the half year period is about $150 million. We had a heavier investment program in Q1 for a couple of different reasons.

First of all, we had our Canadian program going, which is now completed. Secondly, we had more non-op activity in the non-GEMS assets in Netherlands. And another factor was that we were running our original Seafox barge doing some light workovers at the beginning of the year, and we didn't have that going in Q2.

I would point out, and I think we mentioned it later in this presentation, but I'll point out that we are bringing in the Triton-10 barge to do heavier workovers beginning this quarter. Debt down about 3% from the Q1 ending level to $378 million. This is really driven by free cash flow, among other factors. That number is less than 1x our forecasted FFO for '26 at the strip. So we think in terms of debt levels and liquidity, the company is in very strong condition.

We would point out with respect to operations that we did complete the operated K17-FA-103 well and a non-operated well at GEMS, the N05-A-02X, and we'll talk about those results in just a minute. In addition to this drilling activity, we had a great deal of turnaround activity in Q2, both on our operated platforms and plant and on non-operated platforms.

This is customary for Q2. It's typically a pretty good weather period to do facility work with all the manning that's required and all the additional equipment that can avoid some of the rough weather delays that we would get in other parts of the year and that have an impact on Q2 production.

One of the reasons that the July number is so far above the Q2 level are these turnarounds in Q2 plus the fact that we did bring additional wells on production that began to hit during July.

A little bit more on the operations. All of this activity annotated on the map on the right side of the slide. So on the -- a little more detail on the operated K17-FA-103 well, 60% working interest. That is a well that we completed drilling in the second quarter. Subsequent to the end of the quarter, we did the bulk of our completion activity, which was a 3-stage frac that was pumped and perforating a number of the unfracked intervals in the Rotliegend.

Well is flowing at a rate, after a 2-day cleanup test, of 15.7 million cubic feet a day at that 60% versus 9.4 million cubic feet a day back to Tenaz. And the well is being tied into our monopod platform at K-17. In addition, I mentioned earlier, we conducted turnarounds on L2 and L9 along with work at the Den Helder plant during that time. This, of course, had an impact on the Q2 production, as I mentioned previously. And again, we took delivery on the Triton-10 barge is a very versatile piece of equipment that I think is going to allow us to do a lot of high rate of return workovers, heavier workovers typically than we would do with our Kasteelborg walk-to-work vessel.

And also the Triton-10 is versatile in the sense that it can do -- we can do platform integrity work at the same time that we're doing this production-enhancing work on existing wells. And that will be a long-term contract for the Triton-10. We've got a long line of sight on, I think, valuable workovers in the existing well stock.

On the non-op side in Q2, the third well in the N05-A pool was drilled by operator ONE-Dyas, brought on production subsequent to the end of the quarter. This is one of the things positively impacting the July rate. Very, very strong well, 74 million cubic feet a day. We have a 1/3 interest in this well. Along with the original well in the N05-A pool, these are the 2 highest rate producing wells in Netherlands.

We also had the successful N05-A-03 well the numbering sequence there a little bit out of order with the drilling. The 01 well went first, the 03 well went second, and now we have this 02X well that has been drilled and on production. Again, all 3 of them successful in the N05-A pool. Very high rate result on this third well. It had very similar reservoir characteristics to what we had originally in the N05-A-01. And therefore, it's no surprise that the production rate is almost the same.

Also, during the quarter, ONE-Dyas conducted a 2-week turnaround on the N05 platform. Again, this is part of the lower rates that you see in Q2 versus the July rate that we have identified preliminarily based on the accounting to date. Again, it was a strong result in Q2, up 6% from Q1, but affected by those turnarounds and we got this additional impact of what has occurred already in Q3.

On the next slide, we want to give you a characterization of the drilling inventory that we have in Netherlands, including both our operated and non-operated properties. There's quite a bit of information that's presented here. So I'm going to take just a minute to describe each element of the info that we have here. The plot on the upper right is the gross success case size of each of the 111 resource projects that we have in our portfolio. So a combination of 15 contingent and 96 prospective resource category projects on a success case basis, meaning we drill a well, it hits at the forecasted pool size and numbers here that are not met to the Tenaz working interest, but for the project as a whole, what we would call an 8/8 interest.

So the reason we're presenting it in this manner is that we're trying to give you an idea of how large are the projects and prospects that are in the resource category. The way the project sizes are organized here is really what I would call a cumulative distribution or kind of a cumulative histogram. So we put the smallest prospects on the left side of the plot, and we just sort them to the larger prospects on the right side of the plot.

We have put certain statistical indicators on here to give you a little better characterization of the typical size in the portfolio. For example, the median prospect, what we call the P50 is 28 Bcf. Again, success case, this is on an 8/8 basis, not just the Tenaz working interest, pretty good sized prospect at 28 Bcf. It's a log normal distribution of size. So the actual mean or average prospect is significantly larger than the median, 50 Bcf, because it has to take into account the right end of this curve where we have some very large prospects.

We'd have a P90, meaning that 90% of the time, we would expect the prospects to be larger than 13 Bcf in this statistical group. And the P10 means that 10% of the time, they'd be larger than 119 Bcf, again, success case, 100% interest. So again, we would say these are pretty good-sized prospects that we have to drill, again, includes a contingent resource category, typically already discovered fields. Majority of them are undiscovered or extensional in the prospective category. But again, we think a strong set of fairly large prospects.

And then as we feed this gross success data into volumes that are net to Tenaz, I didn't point it out, but I'd like to remind everybody that this is based on an independent assessment by McDaniel. We end up with the results in the table at the bottom. And in this table, we've got both unrisked and risked volumes. At the very top, we speak to our PUD or undeveloped reserve category. This is distinct from the resource category. We've got about 32 million BOE equivalent of PUDs net to Tenaz interest. The total 2P reserve number for Tenaz is about 92 million and the 2P undeveloped reserve is 32 million. A second ago, I referred to it as PUD, but it includes the proved plus probable undeveloped volumes of 32 million. Again, that is distinct from the resource plot up above.

As we summarize down the net volumes to Tenaz, we get the unrisked totals at each of the 1C, 2C and 3C for contingent, the low, medium, high and mean for prospective. There's 2 different sets of nomenclature there for characterizing the range of resource sizes, quite large volumes, especially when you would compare it to our total booked 2P reserve of 92 million at the unrisked level net to Tenaz.

And then on the very right of that table, the bottom 2 cells there, we show a risked contingent volume net to Tenaz of 24 million barrels equivalent and a mean volume of 101 million barrels equivalent net to Tenaz, again, on a risked basis. All of this comparing back to our 2P book volume of 92 million barrels equivalent, which includes 32 million of 2P undeveloped reserves.

So this takes that upper set of data and puts it in net terms, both unrisked and risked to Tenaz. In the bullets that we have on the left of the slide, we just speak to the number of prospects that are included. The first one reflects reserves, which is not included in the plot on the upper right, 15 contingent fields discovered but not in the reserve report and 96 prospective resource potentially fields that are at the resource level.

Final point on the bottom left of this slide is that we've got what we think is a very high-quality ocean bottom node seismic survey over really our main producing area. And really the interpretation of that OBN seismic, which can improve certain prospects and may become bigger as a result of having the OBN generally an improvement in the data quality and our ability to, we think, define these prospects prior to drilling.

That interpretation not included in the results that you see in the table. And as we work it going forward, work the OBN going forward, we hope to get that included in the resource totals that we would present in the future. So again, it's a great deal of information that is presented here in a variety of forms, but we think it gives a reasonable interpretation, a reasonable estimate based on this third-party report of what we have in the portfolio beyond the 2P reserve level.

So let's move over to another topic, and that is just European gas pricing. We just wanted to give you an update of where prices are as of the end of the day today, August 5. Here, we've presented in USD per MMBtu terms instead of euros per megawatt hour or Canadian dollars per MMBtu. 3 curves represented here. TTF in red at the top. And of course, for all of them, we're going to have the historic pricing back to the beginning of '24 in the solid line and then the forward curve shown in the dashed red line.

Heavily backwardated, but all very strong pricing. Again, the big increase in pricing early in '26 and in the forward curve for the -- at least for the first portion of the forwards represented here driven by the Middle Eastern war. The bottom 2 curves show North American pricing. In the green color, Henry Hub prices, historical and forward and the same thing for AECO. So very strong market in Europe. And reflective, we think, over the very long term in the forward curve of full cost pricing at LNG into Europe and in the medium term, the market's expectation of relative scarcity over the next couple of years.

We move on to the storage situation. We have simplified the historic data down to just present the '21 to '26 storage cycles for each of these years. And what we see currently is that storage is at a pretty low level for EU as a whole. As of the end of July, it was 56% full, and it is building at a little bit slower pace than we have seen in previous years. This 56% full level based on a number of market analyses would bring us to a 70% to 75% level at the end of the injection season. That is quite a bit below a typical year. In fact, it's even below what we had in 2021.

And so really -- based on this, we would expect Europe to come in kind of low in storage before we start the withdrawal year, does leave some exposure to cold winter weather. And really with pipeline supply not into Europe, not really being -- having any extra capacity, any makeup in supplies that might be required is going to have to come in from LNG. And to get that LNG, Europe is going to have to compete with Asia with JKM pricing to make sure that these supplies can get into the European market to meet whatever demand does materialize in the winter.

So we present this data just to show the European situation as it stands today and probably does leave the potential, especially in a cold winter, for pretty strong pricing over the next 6 to 9 months.

This final slide that I'm going to discuss today shows Tenaz's hedging position for Q2 '26 through the end of 2028. We don't have any hedges on beyond that. We roughly have hedged about 56% of our European gas exposure for this year, 41% for '27 and a small level, 8% for 2028. Hedge prices at historic levels are actually pretty strong in the range of EUR 30 to EUR 34 per megawatt hour, reflecting both swaps and the collars that we have in place.

Most of these hedges were for the next -- for '26 and for '27 were put on at the time we made the NOBV and GEMS acquisitions to ensure strong returns on those transactions. And we have added some to them during the period since then, particularly during the period since the Middle East war broke out. That has actually led us to improve our hedges a little bit to the pricing levels that are reflected in the data in the bullets on the left part of this slide.

We have also hedged most of our AECO exposure for this year and nearly half of it for '27 at a pretty strong price in comparison to current AECO levels. AECO is a pretty minor product for us, but we do still attempt to manage our price exposure there. WTI is our second most important product, although it's well behind European gas in our portfolio. And we have hedged about 1/3 of it for this year at USD 67.50 per barrel and a little bit for 2027 at an average price of USD 65 per barrel.

We do this hedging program to ensure a suitable level of cash flow. It locks in returns on our capital program. So there's a variety of reasons to do it. It is a hedge book that is below current market pricing. And so we do have some realized hedging losses in both quarters this year. Nonetheless, by historical standards, relatively strong pricing, it fulfills an objective to stabilize our cash flows.

And where we see opportunities, we'll continue to add to the hedge book. Typically, we're going to want to be 30% to 50% hedged roughly over a 2-year period, and we will go higher than that when we see strong opportunities in the market. Again, please note the advisories in our presentation.

And in closing, I would like to say thank you to -- really to all the stakeholders in Tenaz, but particularly to the employees and consultants and service personnel that we have working for the company. It was my honor over the past month to visit our L2 and L9 production platforms and our Shelf Winner drilling rig. There's a large number of people working on the drilling activity. We're picking up the Triton-10 workover barge.

There's a huge amount of technical work that is done in our Netherlands office to design and to manage and implement these wells and a huge amount of work done by our production operations team tying these wells in and doing such a great job of keeping all of the base production optimized within our producing assets.

And it's really as a result of all of this very strong operating and technical work that we're able to report the growth profile that we did in Q2, the production levels that we've seen in July '26 so far in Q3 and this expectation that we have for continued strong growth in the future.

So again, thank you to all of our staff, and thank you to our investors for their support to Tenaz and to all our listeners for your interest in our Q2 report. We're looking forward to talking to you again when we report Q3 later this year.

Hello, and welcome to the 2026 Annual Meeting of Shareholders of Tenaz Energy Corp. Please note that this meeting is being recorded. [Operator Instructions] It is my pleasure to introduce Mr. Marty Proctor, Chair of the Board of Directors of Tenaz. Mr. Proctor, the floor is yours.

Good morning, ladies and gentlemen. I am Marty Proctor, the Chair of the Board of Directors of Tenaz Energy Corp., and I now call the meeting to order. Welcome to the 2026 Annual General Meeting of Shareholders of Tenaz. Today's meeting is being held virtually by way of live broadcast, accessible to all our shareholders who have followed the procedures described in the management information circular for this meeting or information circular for ease of reference. The virtual meeting format alleviates the logistical and travel expenses of in-person and hybrid meetings and is a more sustainable and environmentally conscious alternative to an in-person meeting.

I would like to welcome all shareholders, proxy holders and guests at today's meeting. I would also like to recognize the directors and members of management attending in person, including my fellow directors of the company, Anna Alderson, John Chambers, Varinia Radu, Mark Rollins and Anthony Marino, a Director and President and CEO of the company, as well as the following officers and managers of Tenaz. Bradley Bennett, Chief Financial Officer; Mirzeta Delkic, VP, HR and Sustainability; Jamie Gagner, VP and General Counsel; Brian Giang, VP Finance; Adam Iwanicki, VP of Marketing; Kyle Preston, VP, Investor Relations; and Jennifer Russel-Houston, VP Geoscience; and [indiscernible], he's the Asset Manager.

In accordance with the company's bylaws, I will act as Chairman of the meeting, Jamie Gagner will act as Secretary of the meeting, and Bart Wingerak of Odyssey Trust Company will act as scrutineer. I would like to take a moment to comment on the meeting procedures. Voting on all matters at today's meeting will be conducted by electronic ballot. Registered shareholders and duly appointed proxy holders will be able to vote on each item of business through the electronic meeting platform. Polling is now open for the items of business to be voted upon at this meeting. If you have not already voted prior to the meeting, please vote now. If you have previously voted, you do not need to vote again.

The final voting results will be announced and filed by the company following today's meeting. Questions in respect of an item of business may be submitted by a registered shareholder or duly appointed proxy holder through the meeting platform. A corporate presentation will follow the formal portion of the meeting and questions relating to the company's business and operations will be considered at that time. For efficiency, we have arranged for Brian Giang and Jennifer Russel-Houston, officers and shareholders of the company, to move and second the motions at today's meeting.

Notice of this meeting and the accompanying information circular and form of proxy were mailed on April 28, 2026, to shareholders of record on April 22, 2026. A quorum for the transaction of business at today's meeting is at least 2 persons present in-person holding or representing by proxy an aggregate of not less than 5% of the outstanding common shares entitled to vote at the meeting. According to Tenaz's bylaw, #1, a person electronically participating in today's meeting is deemed to be present at the meeting. I am advised by the scrutineer that a quorum is present and notice having been properly given, I declare the meeting properly called and constituted for the transaction of business.

The first item of business is to receive the audited consolidated financial statements of the company for the financial year ended December 31, 2025, and the auditor's report thereon. I would ask that questions on the financial statement be deferred until the formal business of the meeting has concluded. We will now move to the items of business to be voted upon. The polls remain open for voting in respect of each item of business. You may vote at any time until the last item of business is completed, at which time the polls will close. As a reminder, if you have not already voted, please vote now. If you previously voted, you do not need to vote again.

The next item of business is to fix the number of directors to be elected at the meeting at 6. May I have a motion to fix the number of directors to be elected?

My name is Brian Giang. I am a shareholder. [Audio Gap]

Jennifer Russel-Houston. I'm a shareholder and representative of Tenaz Energy Corp., and I second the motion.

Is there any discussion on this matter? As there is no discussion on this matter, we will proceed to the next item of business. The next item of business is the election of directors for the ensuing year. The company's advanced notice bylaw fixes a deadline by which shareholders must submit director nominations to Tenaz prior to an Annual Meeting of Shareholders being not less than 30 days prior to the date of the meeting. Tenaz did not receive any shareholder director nominations in respect of this meeting. Accordingly, the director nominees for election at the meeting are those named in the information circular for this meeting.

Information regarding the director nominees was included in the information circular. Each nominee has indicated their willingness to serve as a director. The Board has adopted a majority voting policy requiring any director nominee who does not receive a majority of the votes cast at this meeting to submit his or her resignation for consideration by the Board. The Board must determine whether or not to accept the resignation within 90 days following the meeting. Under the policy, a resignation is expected to be accepted -- absent exceptional circumstances.

May I have a motion to nominate each of the directors of Tenaz Energy Corp. specified in the information circular?

I nominate each person specified in the information circular for this meeting, namely Marty Proctor, Anna Alderson, John Chambers, Varinia Radu, Mark Rollins and Anthony Marino be elected as a Director of Tenaz Energy Corp. for the ensuing year. Will someone second the motion?

I second the motion.

Is there any discussion on this matter? As there is no discussion on this matter, we will proceed to the next item of business. The next item of business is to appoint Deloitte LLP as auditor of the company for the ensuing year, and to authorize the directors to fix the remuneration.

May I have a motion to appoint Deloitte as the company's auditor?

I move that Deloitte LLP be appointed as auditor of the company to hold office until the next Annual Meeting of Shareholders and that the Board of Directors of the company be authorized to fix their remuneration.

Will someone second the motion?

I second the motion.

Is there any discussion on this matter? I am advised there is no discussion on this matter. If you haven't already voted on the items of business, please do so now through the meeting platform as voting will close momentarily.

[Voting]

Voting is now closed on all items of business. As mentioned previously, the detailed voting results will be announced by the company following today's meeting. The scrutineers have provided their preliminary report of the results of voting today, and I confirm as follows: in respect of fixing the number of directors to be elected at 6, greater than a majority of the votes cast have been voted in favor of this resolution, and therefore, I declare the motion carried.

In respect of electing director nominees specified in the information circular as a Director of Tenaz Energy Corp. for the ensuing year, greater than a majority of the votes cast have been voted in favor of the election of each director, and therefore, I declare the motion carried and each nominee for election as director has been elected. In respect of the appointment of Deloitte LLP as auditor of the company, greater than a majority of the votes cast have been voted in favor of the appointment of Deloitte LLP as auditor, and therefore, I declare the motion carried.

Is there any other business to be brought before this meeting?

Since there is no further business, may I have a motion to conclude the meeting?

I move that this meeting be concluded.

I declare the formal business of the meeting concluded. Thank you for your attendance.

I will now ask Anthony Marino, President and Chief Executive Officer of Tenaz, to provide a brief business update. Tony?

Thank you so much, Marty, and thank you to all of our shareholders and guests who are attending this virtual AGM. So I'm going to give a very brief presentation [Audio Gap]. Of course, this was a really transformative year for Tenaz. We closed 2 very important acquisitions during the year, and this dramatically increased our Netherlands business unit scale. That's very important for the long term as we provide more efficient growth and better unit costs as a result of having that scale.

The first of those transactions was the closing of the NAM Offshore or NOBV acquisition that we achieved in May 2025. We subsequently renamed that entity TEN, and it is a substantially operated position. And we continue to have a big capital program there, and we think that there's going to be a very long-term growth in a diversified set of projects from that asset base.

Second acquisition was the GEMS project, specifically Hansa Hydrocarbons. We announced and closed that transaction on the same date in October '25. These are non-operated license interests on the -- in the Dutch offshore and the German offshore right at the Maritime border between the 2 countries. These are very high-rate wells that are drilled on these licenses, really the highest rate wells in the Netherlands. And we think it's going to offer a really long-term set of development opportunities in the 3 already discovered pools and a number of very high-quality exploration prospects.

And on both of these acquisitions, we have drilling activity right now. We feel we very efficiently and rapidly integrated these acquisitions. We've been able to establish quite a development program. In the first part of this year, we already had 3 drilling rigs running on our position, 3 jackup rigs in the Dutch North Sea. One of those is an operated rig. I'll touch on that a little bit more in a minute, operating on NOBV lands, now TEN. One was a non-operated rig serving the GEMS development project operated by ONE-Dyas. And in Q1, we also had a drilling rig working on a license in which we have a non-operated interest operated in that case by ENI. So 3 drilling rigs.

We also had one workover barge operating in Q1, and I'll talk later in just a minute about our plans going forward for workovers. So a great deal of activity ramped up, I think, very efficiently by our staff. And this is a set of development programs that we intend to continue for the long term. As a result of the acquisitions and continuing with all of this development activity, we are now the largest natural gas producer in Netherlands on a working interest basis.

Last year, we placed an additional tranche of our senior unsecured notes. This tranche with gross proceeds of CAD 179 million, and we used that to fund the remainder plus cash that we already had on the balance sheet of the GEMS acquisition. We also established during the year, syndicated credit facilities during '25 upsized to CAD 115 million, and that has further [Audio Gap] feel we have plenty of liquidity to fund our future growth. With respect to stock performance, as at yesterday's close, May '26, the shares of Tenaz were up 101% for the year-to-date. That follows an 89% increase in 2025.

And so we're very gratified by that positive stock performance, and we appreciate the -- all the support that we received from our shareholders, and I'll touch on this a little bit more in a minute, too. On the next slide, we show a time line of the major events in 2025. I've discussed a couple of these already. In the first one, we point out the closing on May 1 of the NOBV or now TEN acquisition. That's an aerial photo of our Den Helder plant. We're conducting our AGM, this virtual AGM from Den Helder with our Board, much of our management present and a number of our management team members from the Netherlands business unit as well. And doing the meeting from here, underscores the importance really of this asset and specifically this plant, largest nameplate gas plant in Europe to Tenaz.

The second picture shown there shows the Seafox 4 barge that we began to use in September 2025 for a workover campaign and also for continuing asset integrity work that we routinely conduct on the assets. So we use Seafox 4 initially. It worked for us into Q1 of this year, and we will be picking up a new barge probably in Q3, the Triton-10 barge, which we think is very nicely suited to a real wide range of workover activities that we have available in the existing set of wells, it should be, we think, quite high rate of return, very diversified set of opportunities. And we think that's a long-term contract that we put in place. We think that those workovers should continue for a number of years and provide additional support to a significant growth profile in production that we think that we will have for the company.

Next activity shown on the time line is the GEMS acquisition with a picture of the N05 platform. Again, as I mentioned earlier, operated by ONE-Dyas, highest rate well in the Netherlands for the existing well there. There's another well -- a development well that is already on production. Drilling is going to continue probably for the rest of this year on that asset base and continue to quite rapidly ramp up production there. And the next event shown in November '25, is the Shelf Drilling Winner rig arriving to work for Tenaz, again, under a multiyear contract.

We've identified a very large number of drilling opportunities, and we intend to have the Shelf Drilling Winner here for several years, if not longer, and expect continuing even improvement in our costs as we go forward and move along the learning curve in these drilling activities. It has been successful to date, and we fully expect that to continue on what is really a pretty low-risk set of drilling opportunities on the TEN assets. So we're very proud of what we've been able to accomplish this year. I want to thank all of our employees who have been involved in this. It was a big effort on the operated assets to really transform the business unit from one that was maintaining production to one that is [Audio Gap] In our production profile.

On a numerical basis, I'm going to use this next slide to compare the quarterly results for Q1 '26 to Q1 '25, just to give you a snapshot of the improvement in results in the company, the growth that we've seen in all of these categories. Production up substantially to over 16,000 boe/d in Q1. This is consolidated for the company. It's not just Netherlands. We've actually had a very successful program in Canada as well. And I want to thank the Canadian employees for their work in a super efficient program that has been maintaining production, will lead to a small increase this year, very low CapEx and positive free cash flow from that asset.

So that has contributed to the production result as well. And we do expect pretty steady continuing growth out of our asset base as we look at the next quarters and actually probably for the next number of years with this large set of drilling and workover opportunities that we have. Reserves as at year-end '25 as compared to year-end '24, shown here, a substantial increase, reflecting bringing in both TEN and GEMS and identifying a number of development opportunities. We also published an independent resource report, both contingent and prospective resources for Netherlands, and there are substantial volumes there as well.

And in fact, much of our drilling comes off that -- those resource locations as opposed to just the ones that are on the reserve report. CapEx, of course, up substantially to run this much bigger program. The numbers you see reflected here are annual totals at guidance level for this year compared to the total that we recorded for 2025. It's a self-funded program, which still results in very substantial growth, and it's something that we would like to continue at high levels of activity, generating more and more cash flow over time, presumably more and more free cash flow and as we continue the growth each quarter and each year.

Looking at FFO per share, again, up substantially as we see the impacts primarily of higher production, but some increase in prices as well. And as I'll touch on in just a minute, we do expect that increases in FFO will continue, again, always subject to commodity prices. And our share price shown at the end of Q1 '26 as compared to the end of Q1 '25, up substantially. So if we turn to the next graph, this is a multiyear -- historical result and projection of our production, netback and then resulting FFO at the consensus of the analysts covering our company.

So again, not internal projections. These are independent view of the analyst community. Of course, they use different prices and commodity prices in their projections, expecting a pretty substantial increase in production, again, not only for '26, but continuing to '27. We would expect to continue to have increases in production after that as we continue our capital program. Looking at the middle panel there, this is our operating netback as projected by this group of analysts. It's going to be dependent on commodity price. We are -- we do have a very -- I feel, sophisticated hedging program that will modulate the sensitivity of our netback to prices. For example, we're a little bit over 50% hedged this year for our dominant product, TTF, natural gas.

The -- although we are going to be dependent to some degree on commodity prices, the fact is that as we increase our production, we do expect our unit cost to come down. And so actually, even if we had constant prices, we would expect to have some improvement in operating netback. The product of production and our corporate netback after accounting for interest and taxes results in FFO, again, historic result for the 3 years '23 through '25 and then analyst consensus projection for '26 and '27. If we have this production increase and we have [Audio Gap] very excited about the future that it represents.

In closing, the last slide that I'd like to use here is just a graph of the Tenaz share price. We have seen a pretty substantial increase since the recap originally occurred in August '21. I can assure you that we're going to do everything that we can as the employees of the company to -- continue to deliver for the shareholders going forward. So that concludes the presentation. My final point I would like to make is that, we're very appreciative of the work of our employee group here in Netherlands and in Canada and our accounting group that we have in Poland as well.

We are very appreciative of the support that we've had from the Netherlands government in the rejuvenation of the Dutch offshore and increasing production here and domestic energy security. We appreciate very much the support and cooperation of our partners, our partner companies in Netherlands. We're supportive, and we recognize what a great environment we operate in with these communities that we are located in, in Netherlands.

And finally, of course, I want to thank our shareholders for their investment in the company and the support that we've had to date. So for this broad stakeholder group, I assure you that we are going to do everything we can to continue to deliver as we go forward. So that concludes my remarks. And again, we thank everybody who has tuned in for this virtual AGM.

Hello. I'm Tony Marino, President and CEO of Tenaz Energy. Thanks for joining our Q1 2026 update. I'd first ask you to note our investment advisories on Slide 2. I'm going to begin with a discussion of our operating and financial results using the first Slide 4.

So in Q1 '26, our production was up 4%, reaching a level of approximately 16,200 BOE/D with the vast majority of that production coming out of Netherlands. FFO for Q1 '26 was approximately CAD 65 million. That was a 4% increase from the fourth quarter of '25. We certainly had our most active capital program we've ever had in the company's history, 3 offshore jack-ups running on licenses in which we have an interest.

I'll cover it more later, but one of these operated in 2 non-operated drilling rigs in the Dutch North Sea. An offshore workover campaign going in Q1 as well. And we also drilled 3 gross wells in Canada that we operated.

Our CapEx for the first quarter was CAD 92 million. That's about 1/3 of our 2026 plan. We'll talk about an increase to our capital program. It will probably end up being about 30% of the capital for the year as a whole with that increase. And certainly, I would say, probably our most capital-intensive quarter that we expect.

Our operating netback in Q1 '26 was very, very strong, over $57 per boe. Reasons for the higher netback, we had higher pricing in this quarter, in part driven by the outbreak of war in the Middle East at the end of February and driven by really an improving product mix in the company with higher levels of Netherlands production in the mix because of the acquisitions and continuing organic growth.

Our net debt as of the end of Q1 was $389 million. That was an increase over our year-end debt level because our capital program exceeded FFO. It's very front-loaded on capital, as I talked about earlier.

And of course, we see the production results, and resulting revenue and cash flow coming in mostly after Q1. We do expect to have substantial free cash flow at the commodity strip that we have currently during the year, even with the capital increase that we're announcing Q1 results.

And it's quite a reasonable debt level. While we do expect deleveraging further during this year, if you just take that debt level and compare it to our expected FFO for the year, it would be about a 1x multiple. We did record a net loss of CAD 111 million in the first quarter of '26.

This loss that we recorded is really just due to the requirements of marking to market our entire hedge book for '26, '27 and '28 and recording that entire change in the mark-to-market value in the first quarter.

As at the end of 2025, as at Q4 '25, we had a small gain -- unrealized gain recorded on the hedge book that shifted to a negative position, unrealized loss position is recorded in Q1, and it's the reason for the loss that we recorded here.

This hedge accounting of IFRS is sometimes a little bit counterintuitive in that when you have higher prices in a quarter and certainly, it's been very dramatic with what has happened with the Middle Eastern war, it actually can lead you to report quite a substantial loss.

If prices decline, that hedge book position reverses and you may well report high net income when you have a lower price period. Counterintuitive, a little bit confusing, not very reflective of our increasing cash flow and what we expect to be substantial free cash flow.

But nonetheless, this is how the mark-to-market accounting under IFRS works, and it was the entire reason for recording this loss.

Slide 5. Let's review our operating activity during the quarter. On our Tenaz Energy Netherlands or TEN operated assets, first of all, we finished drilling our first well with the Shelf Drilling Winner jackup that we are operating. This well called the K07-FB-103 well, which is the K7 also often referred to as the K7 Papa South pool.

So we finished drilling this well, and we have now completed it. We brought it on production during Q2 at a rate of 7.8 million cubic feet a day, that's 3.6 million cubic feet a day net to Tenaz. This is very close, almost exactly our expected production rate actually flowing into the system that we expected during the first month of production.

So as expected, tested at a higher rate, and this is the rate at which we put it on production. The Shelf Drilling Winner rig then moved to the K17 platform, began drilling the K17-103 well. This, we have a 60% working interest in. This well is still drilling.

We do intend to complete it with a multistage stimulation in the horizontal lateral. And that activity, we're still scheduling with a stimulation vessel that will occur a little bit later this year. We also conducted an initial barge workover campaign on the K15A platform with a barge that we have since released and we have no barge running at the moment.

We'll explain later, we're going to pick up a new more versatile barge later in the year. That K15A program added about 7 million cubic feet a day of productive capacity. That would be 3.2 million a day net to our interest, quite a successful program. These workovers tend to pay out pretty fast, don't require as much capital, of course, as drilling a new well, and they can give you some quite good production results.

Talk about the forward activity a little bit later on. At GEMS, operated by ONE-Dyas on wells that we have a 33.3% working interest. First of all, production continues on the first N05A pool, well #1 at a rate of about 74 million cubic feet a day or around 24 million to 25 million net to our interest. With respect to the drilling, they finished the first development well in this program.

It would be the second well in the N05A pool. This well is called the N05-A-03. It was drilled and completed and brought on production gross rate of 40 million cubic feet a day, quite strong productivity and 13.3 million cubic feet a day net to Tenaz.

Again, that's in addition to the N05-A-1 well that is still on production at 74 million cubic feet a day gross. That one is the highest producing rig well in the Netherlands. After the N05-A-03 well, the ONE-Dyas operated drilling rig began drilling the second development well and this year program would be the third well in the N05A pool. This well designated as the A02 well, and this drilling is continuing.

Third rig is operated by ENI at the pool in the -- on the L10 license. So here, we have a 21.4% working interest. ENI finished drilling that L10 Malachite well and has tested at -- did a step rate test, stabilized rate of 14.5 million cubic feet a day, and they are in process of tying that well in. Again, that one is 21.4% working interest.

Canada, we drilled 3 gross wells. 2 were in the Ellerslie member of the Mannville formation. These are multilateral wells with no stimulation, and they are currently on production at a rate of 450 BOE/D, which is nearly 400 BOE/D net to our interest, 85% oil, the rest AECO gas.

The third well was drilled and completed in the member of the Mannville formation, again, 7/8 working interest. It is a single lateral with multistage Fracs, and it is currently producing at 245 BOE/D, around 215 BOE/D net to our interest, its oil percentage of that oil equivalent rate is 72%. That well continues to [indiscernible] water cuts. So successful activity, I would say, throughout this very active Q1 program.

On Slide 6, I'll talk a little bit about our capital program for the rest of the year and the expansion of the budget. So the first thing, we are announcing a $25 million increase to our targeted capital program. Previously, we've guided to CAD 250 million to CAD 275 million. We're now targeting CAD 300 million investment for the year. We do expect to be generating at this level meaningful free cash.

And as we look at our alternatives for using that cash, we do have an ongoing NCIB program. We will be reducing debt levels. But we do think that the very highest use that we could have of free cash flow, given our high rate of return on the development program is to have more organic development and more organic production growth.

The incremental capital goes toward an expanded workover program, bringing in a new barge. I'll cover that in just a second, an additional non-operated well that we expect to occur late in the year.

And also, it allows for stimulation of the third well in our operated program, which is a little bit more expensive than an unstimulated well as we had planned previously. So more workovers, the additional nonoperated well and kind of an expanded better completion scope for the third well in our operated drilling program.

The barge is shown in the picture on the right side of the slide, Triton-10 barge, we think quite a versatile vessel. We intend to have it in place during the second half of the year. We've already identified 50 workover opportunities. In aggregate, these are going to have, we believe, a risk IRR in excess of 100% under the current commodity strip and even under much lower pricing, if it occurs, we have very strong returns.

Again, we get rates of -- rates out of these workovers, and they don't take that much capital because the vast majority of the capital investment occurred at the time of drilling. So it's quite an efficient way to employ capital.

We have actually a very long-term set of workover opportunities. The scheduling we have now takes this barge already out into 2029. The barge is quite versatile. It can also help our completion program when it's more efficient. We can have the barge complete wells rather than using the drilling rig, which could then be employed to do further drilling activity on the very large opportunity set that we have for new grassroots wells as well. All of this, of course, occurring from existing platforms.

And again, all this activity kicks in later in the year. We don't expect very much of a production impact from it during 2026, but we should have improvements in our already further growth in our rates than we previously expected in '27 and the years beyond as a result of this modest expansion.

I'd like to briefly discuss European gas fundamentals. We've talked about this in previous quarters. We show on Slide 8, an update of our storage curves for the European Union, actually 9 years of data here, including the current year '26 shown in the dark red curve.

We already knew that we came into the heating season for '25, '26 at relatively low storage levels. We then had a pretty cold winter overall in Europe. And as a result, we're running with pretty low storage compared to the previous 9 years as we have now moved into -- we're in the shoulder season moving into the injection season.

As I think everybody knows, I covered the next couple of bullets, Europe has begun really relying more on just-in-time deliveries via LNG vessels for supply, not as much as on storage in the past and pipeline deliveries into Europe are pretty maxed out already.

So it's really become a storage of LNG delivery. It's kind of a difficult position for Europe to be in, given the problems that have emerged in the Middle East with LNG supply. It's going to be a bit harder to refill the storage to typical levels. We don't know when the problems in the Middle East are going to be resolved.

Everybody knows, I think that biggest LNG facility in the world in Qatar has had substantial damage. Of course, there's no delivery of LNG happening out of it along with no oil flows out of the past Strait of Hormuz.

So Europe has quite a challenge in front of it to rebuild storage to an adequate level as we go into winter. The EU had, had mandates to reach 90% levels previously. I think those have already been relaxed to some degree. And again, Europe is going to be in a position of having to compete for LNG supplies with Asia.

In a sense, the TTF change in gas price that occurred as a result of the war has been attenuated as a result of it occurring during the shoulder season, but we think that this competition for deliveries between Asia and Europe is going to increase as we move into the summer power season in Asia.

So kind of a hard situation for European storage at this point. We show the pricing curves historically and in the dash lines and the forwards on Slide 9 for TTF in red and then for Henry Hub in the lighter green color and AECO in the dark green color.

I'll point out that these prices were as of May 1, it's volatile every day. For example, as we are recording this on May 6, there's been a substantial drop in prices today, really depends on the news flow out of these negotiations and the military activity in the Persian Gulf.

You haven't really seen much of a reaction out of the NYMEX or out of AECO, but there, of course, has been this big move up in TTF for the reasons we just talked about. It's still a very backwardated curve, doesn't show much incentive for seasonal storage as well, but it does vividly illustrate the impact of the war and the higher prices that we have in our TTF gas. Our product mix for this year will be close to 90% TTF for Tenaz.

Moving to Slide 10, I'll just review again our commodity hedging. We talked a little bit about this earlier and the impact on the net income. So in our typical hedging program, in the next 12 months, we'd intend to have -- or for the current year, let's say, we'd intend to have about 50% hedged and around 30% for the 12 months after that.

In our current condition, our overall corporate price exposure for the next 24 months is about 1/3 hedged. Breaking it down into the individual products for TTF, our most important exposure, this is going to ultimately be 90% plus of our product mix, we are 55% hedged for '26.

The average price on that just under EUR 32 per megawatt hour. That's just about CAD 15 per Mcf for methane, CAD 15 per MMBtu. For '27, it's a little bit over 1/3 hedged. Average price there slightly higher, EUR 33.60 per megawatt hour, corresponding to a price just a little bit under CAD 16 per MMBtu.

And then a small position for 2028, about 2% hedged at an average price of EUR 34/meg corresponding to about CAD 16 per MMBtu. WTI isn't nearly as significant product for us. We're about just over 1 quarter hedged for '26.

Average price there, USD 67.50 per barrel, small position for '27, 6% of estimated production at an average price of USD 65 per barrel.

And AECO, even less important volumetric product in our product mix and a very small part of our revenue. We were hedged for '26 and '27 at an average price of CAD 3.14 per MMBtu. That's well in excess of the market price representing around 63% of our '26 production and probably just under half of our '27 production.

So again, a meaningful hedge book at what are really historically quite strong prices and the remainder exposed to the currently higher market prices for European gas and WTI.

And finally, with respect to '26 guidance, kind of a reiteration of what we already talked about on Slide 12, projecting 21,000 BOE/D midpoint for '26 and a capital program targeting CAD 300 million of organic investment, which is up $25 million driven by the things I talked about earlier, the barge addition of an nonoperated well and stimulated well -- a third well in our program, our operated program.

On the right side, we just outlined the individual wells that we expect to drill in our current plan, the working interest and a rough time line for when those activities are going to happen.

So in closing, I'd first ask you to again note our investment advisory on Slide 13. And let me thank you for your interest in Tenaz. The next opportunity we'll have to talk is at our AGM scheduled for May 27. So again, thanks for your interest, and we look forward to our next opportunity.

Hello. I'm Tony Marino, President and CEO of Tenaz Energy. Thank you for joining us for a brief presentation about our 2026 budget. I ask you to note the investment advisories we have at the beginning and end of this presentation. Our budget guidance for 2026 is a capital investment level of CAD 250 million to CAD 275 million. This program is up substantially from around $100 million in 2025. This, of course, is driven by our ownership and operation for a full year of Tenaz Energy Netherlands, what we used to call NOBV and our non-operated ownership in the GEMS project as well as our previous non-operated interest in Netherlands.

With this substantially higher capital investment, we do expect to generate quite significant organic production growth. We're showing a production range of 19,500 to 22,500 boe/d for next year, average for 2026, midpoint of guidance of 21,000 boe/d, and that's more than double our calendar year average for 2025. Of course, in 2025, we closed both acquisitions, and we don't count the production levels until after closing. But even compared to our pro forma production rate of 16,000 boe/d after those acquisitions in 2025, it's still quite substantial growth.

What we average for the year and what our exit rate will be, of course, is dependent on the timing of our project execution and how successful they are. But in our base forecast, we think that production rates at the end of 2026, what we call our exit rate could be as high as 27,000 boe/d. And of course, given that the production rate builds in 2026, we think we're set up for an even stronger production level on average in 2027 as a result of this capital program. And presumably, we'd have a strong capital investment level in 2027 as well, which would continue to build production growth.

In terms of comparison to our FFO or cash flow generation, we think that this capital program will roughly balance or be just inside under current prices of our FFO levels. And in that sense, it would be self-funded. Of course, a feature of our capital program and of our net cash generation for next year is that we do have the earn-out on the TEN assets or on the NOBV acquisition, and that is an incentive for us to have investment into the TEN assets. So if we look at the operated program, we already have the Shelf Drilling Winner in place, making a hole on our first well in the Netherlands. Including that well, we would envision a 3 gross, 1.6 net well program on the TEN assets.

We would also continue our barge workover campaign that is currently in place, and we may well use the drilling rig for certain workover activity too. Workover has a very high rate of return, and there are certain workovers that are better suited to the drilling rig. With respect both to drilling and some of the more complicated workovers, this is certainly a step change in activity from what had previously been conducted by [ NOM ] on the TEN assets.

There's also a significant level of non-operated activity. In fact, in Netherlands, the capital program is roughly equally split between operated and non-operated investment. So first of all, at GEM -- GEMS is the bulk of the non-operated investment. Operator ONE-Dyas envisions a 4 gross well program. That would be 1.4 net wells to Tenaz interest, starting with the finishing of a well in the N05 A pool that was started and suspended prior to this current drilling program.

So a combination of development and potential exploration wells in the GEMS program. In the Eni operated L10 block, the Malachite well will be drilled and finished in 2026. We have a 21.4% working interest in that well. So including our operated drilling and these two non-operated programs, there are actually three rigs running now offshore Netherlands. That's most activity that we've had in that province for a long period of time.

And Tenaz is involved in all three of these, and that is what is driving the bulk of this production growth. Again, this is 99% TTF gas, maybe 1% condensate. TTF strong product. We'll touch on that market in just a minute. But we would point out that the current TTF price -- the spot price is about CAD 13 per MMBtu.

So again, strong pricing generates good cash flow in this market. Canada is certainly a much smaller part of our program, roughly 10% of the production base in the company, maybe slightly higher than that. We're going to continue some growth in Canada, not quite at the pace that we've had for the last number of years ever since we affected the recap back in 2021, but still on the order of 10% growth in Canada.

We'll be doing that with a 3-well program, 2.6 net wells. Two of these will be multilaterals in the Ellerslie formation. We've had a great deal of success with these low-cost unfracked multilaterals in the last couple of years. We'll continue that program. The third well, we would plan to have in the Sparky formation. This is a single lateral that will be fracked, similar really in a lot of ways to the Rex formation, where we have a great deal of project inventory that we'll be pursuing over the next number of years.

Sparky is probably a little more permeable, a little higher water saturation, that will be offsetting successful drilling by another company. And to touch on the economics of this, we still see quite high rates of return. We realize that there's been a big drop in WTI prices over the recent period. But we point out with Dyas of USD 13 per barrel prompt for WCS and about $12 per barrel in the forward curve. We still generate about a $60 per barrel price for our crude here, which trades WCS without having to introduce any condensate to sell the crude. And at that price, again, we have quite strong returns. So at present, we intend to implement this Canadian program.

Actually, when this rig is picked up, we think in Q1 in Canada, we'll have four rigs working, three in Netherlands and one in Canada on Tenaz assets. Next, let's briefly discuss the TTF gas market in Europe. Everybody is aware, there's been increases in LNG supply. We think that's going to continue. A number of projects are going to be built in the U.S., and we'll have increased supply from Qatar as well. The fact is that Europe will continue to have to compete for LNG supplies with Asia.

There is very likely to be a cutoff of Russian gas into Europe, currently about 12% of the supply into the EU. And almost certainly, that's going to be replaced not by any pipeline supply into Europe, but by LNG. If you take a look at LNG netbacks, they actually had gone negative in -- when supplied from the U.S. Gulf Coast over the past number of weeks. Now with the drop in Henry Hub just in the last couple of days, I think they've shifted back into positive territory, but certainly not the very high netbacks that we had previously.

If you look at the forward curve and the LNG netbacks are actually back into negative territory. So again, this may have an impact on how many of these proposed U.S. projects actually end up being built. But again, we do expect an increase of supply into Europe. We do think that the full cost to supply LNG into Europe is a pretty good indicator of where TTF prices may have a floor and that full cycle cost is actually very close to where TTF trades today, somewhere around EUR 27 per megawatt hour. And as I mentioned previously, this will translate at current exchange rates to around CAD 13 per MMBtu.

In the near term, for the remainder of this winter, storage is actually at fairly low levels in Europe in comparison to previous years, as you can see on this plot in the bold red line. Again, whether or not that has a big impact on winter pricing will depend on the weather in Europe. But the fact is that storage is not as full at this point as it typically has been. So I'd say that specific aspect of it, not a negative. We are aware, of course, that a lot of this supply into Europe is now just in time via LNG rather than relying probably to the same degree on storage that we -- that the market has in the past. We do very actively hedge this product.

In fact, for the remainder of this year, Q4 '25, we're a majority hedged, and we're maintaining a hedge position primarily driven by TTF, but also by hedging AECO that ensures about half of our revenue level for 2026. So we'll continue to add to that position as we go forward in time. We've got a pretty healthy hedge position on in '27 as well. At present, really unhedged for oil as we look ahead to '26 and '27, not a huge product in our portfolio. And at present, we are largely unhedged both for the commodity and for the WCS differential.

So in conclusion for this brief presentation that we have made, we think that this year's budget and the guidance that comes out of it for increased production is indicative of our very strong organic growth opportunity that we have present in the company. This was set up by the transactions that we've made over the past couple of years, particularly those that we closed in 2025. By no means are we out of the M&A business. It's still a very, very important part of our activities. We feel we have a very good transaction pipeline in place, probably the best it's ever been.

We don't make any guarantees it will come to fruition. It is certainly going to be our objective that any deals that we make add value for the existing shareholder set. But again, it's much more of a combination message than we've given in the past. We have very strong organic growth and I think a great M&A upside in the company. The management team is experienced in both parts of this business. Certainly, we've had success in the M&A historically, and the M&A is designed as it's doing in Tenaz today to set up this organic growth, and we continue with both elements of our strategy to attempt to add value for the existing owners.

Final point is that the team remains fully aligned with our shareholders. We were there at the original recap transaction 4 years ago. We as a director and officer group, we have pretty significant ownership, around 16% of the basic shares, nearly 20% on a fully diluted basis. We did note this month that the directors and officers fully converted their stock option and warrant position. We have extinguished all of those and have converted 70% of that position into share ownership, adding to that percentage on a -- from where it was before on a basic basis.

And I'll point out that beyond just the director and owner -- director and officer group, every employee in the company is incentivized as a shareholder of Tenaz. So every employee is incentivized to deliver for the full shareholder base, and we think that's very key to the company's historic success, and it's going to be equally important to our success going forward.

So that concludes my presentation. Again, note the advisory at the end of the presentation. We appreciate your interest in Tenaz, and we look forward to our next opportunity to report to shareholders. Thank you.

Hello. I'm Tony Marino, President and CEO of Tenaz Energy. I'll cover a PowerPoint describing our GEMS acquisition. I ask you to please first note the advisories we have at the beginning and the end of the presentation. We'll start with a brief corporate overview that will incorporate a couple of the aspects of GEMS.

First of all, the strategic model of the company remains the same, focused on acquisitions in the overseas market. Current asset base is a significant production foothold in Netherlands, making us today, we believe, the largest producer in Netherlands, except for the state company, EBN, and we continue to have our Canadian oil growth project. Two major transactions closed this year, NAM Offshore or NOBV, now called TEN within Tenaz , which we closed at the beginning of May. And the acquisition we announced today, the nonoperated interest in the GEMS project, which was a signed and closed transaction executed earlier today.

Market cap before the transaction, about CAD 575 million. After the transaction, we'll have a little bit over $400 million in debt. That's up from $100 million prior to the deal with that $100 million, including the estimate that we have made for the earn-out on the NOBV transaction. Pro forma production and by that, we mean had we owned both the GEMS and the NOBV assets for an entire year of 2025 would be 16,200 BOE/D. We'll show you our new guidance number at the end of the presentation. And our drilling and development CapEx estimated for the year, CAD 100 million to CAD 110 million. This only counts CapEx after the dates of closing of the -- each of these transactions and little change -- no change in the insider ownership of the company.

On Slide 5, we have the same 4 panels that we have typically shown to illustrate the progress of the company since we executed the recap in 2021. And again, in this, we will show the production for GEMS added on to the previous assets in the company, so we had owned them for the entire 2025, which we're calling our pro forma presentation. FFO, again, added from GEMS in the lower left panel. Significant increase in NPV as well with the addition of GEMS shown at the 2P reserve level for this plot on the upper right and the share price prior to today on the lower right panel.

We just illustrate the capital structure of the company. First of all, showing net debt progression in the upper left. The addition from the investment in GEMS and the issuance of additional senior secured notes to cover a portion of that brings us to our roughly CAD 400 million level as of today. On the lower left, we illustrate the addition to the notes issue. So left column, we originally placed CAD 140 million of 5-year notes, 2.5-year non-call at November '24. Those had a coupon of 12% for the par bond that we issued.

In this transaction, as an additional private placement, really an add-on to that offering, we placed an additional principal amount of CAD 165 million. The coupon rate on that is still 12%, really all the terms and condition rate, the maturity dates, the call dates remain the same for the new influenter, the new tranche of notes. They were, however, issued at an 8.4% premium to par value. And with that, you generate a 9.5% effective interest rate or yield to maturity. Call date remains May 2027. Maturity date, if never called, remains November 2029. So for purposes of the increment, it's about a 4.2-year bond with a 1.7-year non-call would be a way to think of that. If you look at the middle part of the lower half of the slide, we also point out that we have placed a revolving credit facility. This is a secured reserve-backed loan. It's a -- from a syndicate of Canadian banks led by National Bank and CIBC. Goldman Sachs is also a participant. This $115 million facility is undrawn. It will have a 2-year term, and it will have semiannual redeterminations of the borrowing base.

Interest rate is at a spread to Canadian or U.S. benchmark, depending on which currency is drawn, and it will work off a pricing grid based on our total net debt to EBITDA at the current ratio that we have versus the Canadian for benchmark, we would have an initial rate of 7.13% if it was drawn, but this issue -- this RBL is not drawn as of now. Upper right is the share count as last reported at the end of the second quarter, no changes to that. There is a small amount of share issuance in this deal that we'll cover later, but those shares are not included here. And actually, the number of shares will depend on the market price for the next 20 trading sessions.

On the lower right, we just briefly show the metrics for the GEMS acquisition, a little bit over 2x cash flow or FFO and a projected payout of less than 3 years on an a tax basis in our internal projections. For the corporation as a whole, after the GEMS acquisition, we'd have a net debt-to-EBITDA ratio of 0.9x. That's well inside the targets of the company, but we would seek to delever that over time as we build free cash out of our assets in the company today. And as of the announcement of the deal, our ratio of the new net debt number to enterprise value, again, at the start of trading -- at the end of trading last Friday would be 41% debt-to-EV.

This Slide 7 illustrates a reserve summary for the company as a whole. So this shows reserves at the PDP, 1P and 2P levels based on independent report by McDaniel using the McDaniel 3 consultant average price deck. It includes both the Tenaz assets and the GEMS assets. Total reserve number, if you put that together with Tenaz's reserves at the beginning of this year, totals 92 million barrels equivalent. And on the lower right side, we show a production profile generated by McDaniel at the 2P level, and this would not include any production out of contingent or prospective resources that shows pretty strong growth for the company, approaching the 25,000 BOE/D level within the next 4 years.

So let's move off of the corporate tools and talk specifically about GEMS asset that we are buying. And this was an enterprise deal. We bought a private company that has a nonoperated interest in this gateway to the MS project offshore in both the Dutch and German maritime sectors. So first of all, to note on the map, the licenses that are in blue are ones that were already -- in which Tenaz has already had an interest. The ones shown in the orange color are the new licenses that come with the GEMS acquisition. You can see that they are right at the Maritime border between the Netherlands and Germany.

We do think that this is a great asset base. We do expect very strong production growth out of it. We think that will -- given the quality of the wells and the low-cost nature of the development, we think that it will be a pretty high rate of return development project and acquisition. And it really just builds on what we've attempted to establish in the Netherlands initially with the non-op deals a few years ago and now with a very key addition of the NOBV cornerstone asset, we're adding to that and adding scale in the Netherlands and improving our growth rate. So really building, I think, a very significant business here in Europe and particularly at this point, concentrated in the Netherlands jurisdiction.

As we're going to talk about later, these are very, very high rate production tests and current well production. It's got -- the asset has considerable unused infrastructure at this time, and we think that the wells with development are capable of significantly utilizing that infrastructure, allowing more production and cash flow out of the asset at a pretty good growth rate. It's very high-margin production, low OpEx projected in the range of EUR 5 per BOE, including transport costs, very low royalties, really no royalty on gas on the Netherlands side and a 5% royalty on the German side after deduction of operating expense. It's a pretty new asset, only the one platform now, very limited number of wells and as a result, very low decommissioning cost.

So high rate, high margin and low decline, all desirable characteristics. Very unique feature of this project is that the power source to operate the platform and the things that will ultimately go with it compression drilling rig are going to be powered by a wind farm that is just on the German side of the maritime border, maybe one of the very lowest emission projects, I think, that you could find anywhere in the world for hydrocarbon production, very desirable characteristic, something we're proud to be associated with.

So if you put all this together, the quality of the wells, the nature of the infrastructure and it's capacity today, state-of-the-art platform, ability to develop at low risk and explore at relatively low risk. We think it's really one of the very highest quality assets, if not the highest quality asset in the North Sea in this premium TTF market. So moving on to a little more specific asset description on Slide 10. A little more detailed map.

First of all, the wider area map showing the distribution of gas fields, including the onshore fields. This is located relatively close to shore, about 30 kilometers on average from shore, pretty shallow water, 25 to 30 meters. Pretty good operating environment, I would say, from a standpoint of weather and proximity and availability of services. So all there, again, very desirable characteristics. There are 5 licenses included on the German side of the Maritime border, 3 on the Netherlands side. Our interest vary from 22.5% to 45% in these licenses.

In the initial producing pool was N05-A due to unitization of 2 of the licenses, we have a 33.3% interest, including in this first well at 77 million cubic feet a day of current production. And again, this 33.3% interest. The existing N05 platform is tied into the NGT gas gathering and transportation system. In this system, we already own a 21.4% interest. So I think that the project is quite a boon to the midstream asset as well, and we're happy to have that ownership in NGT as well as the upstream position that we've gained in this area with GEMS.

We do expect production to increase. It's all dependent on timing and well productivity, and I'll talk about the development slate here a little bit more in a minute. But we would estimate currently that on a net basis over the course of the year, production should build such that it can average around 7,000 BOE/D or 42 million cubic feet a day net to Tenaz next year. That will be after 2 development wells, 1 extension well and probably 1 exploration well to be drilled over the next year. There -- in addition to the existing producing N05-A pool, again, this is the line making 77 million cubic feet a day from a single well, highest rate well in the Netherlands. There are 2 other pools on the N04 license, N04-A and N04-C that have been discovered and tested both at pretty high rates, 50 million cubic feet a day and 20 million cubic feet a day, respectively, that are classified as proved and developed within the 2P category. And there's a platform plan to be set that will allow those fields to be developed probably with production commencing in about 2028.

So just 3 pools in the 2P report, the N05-A, the N04-A and N04-C, totaling about 19 million barrels equivalent to Tenaz and under McDaniel's independent analysis, a pretax value of approaching CAD 600 million. And again, we'll detail the further development activities. Producing zone is the Basal Rotliegend. The Rotliegend sandstone, of course, is kind of the mainstay of gas production in Northwest Europe. We find that it's quite consistent across the prospective fairway here, really consistent for 40 or 50 kilometers using well control. It's further been mapped with a combination of 2D and 3D to identify this large number of prospects.

So well correlated and consistent in the prospective areas. Basically, those areas off the very structural highs that have proved to be [ bolt ] structures in the past. So gas in the trapped areas in the lower part of these structures. Speaking to the platform, we really do have a state-of-the-art installation here, brand-new platform as of August 2024. It is an automated platform under typical conditions unless there's special activity going on. It is not a manned installation. Our team at Tenaz visited this platform prior to the closing, and we were very impressed with what we saw.

First of all, a very motivated staff on the part of operator ONE-Dyas. ONE-Dyas is the largest private gas and oil company in Netherlands. They have done a great job on design, installation. It was interesting. We actually had a chance to see this platform when it was being built as well in the dock and now to see it in operation was really quite a great experience for us to see how all this design concept with automation and really a degree of artificial intelligence had been installed on the platform. So really, our hats are off to ONE-Dyas for what they have achieved here.

And on the inset map, we just show a little bit more detail of the development fields, the location of the wind farm that is going to supply power to the platform and also a couple of the exploration prospects. With respect to development on Slide 13, again, we have the one producing field, N05-A with a single well, in which 77 million a day at a 33.3% interest. That well had been discovered by an earlier test at 54 million. This well has been -- the actual production well has been ramped up to still a choke rate of 76 million cubic feet a day producing into NGT, heat content of 809 btu/scf. We think that, that is probably pretty consistent throughout the area based on a number of wells that have been tested as far as heat content, a desirable gas into the Netherlands local system.

The development of the N05-A pool is going to continue. We think probably with drilling prior to the end of the year, 2 development wells that are required to completely develop that pool, drilling an extension prospect called the N05-A Noord and potentially also an exploration well to Diamant or perhaps to another prospect in the area with a final well really to be determined as we progress that drilling program. The -- and with the assigned volumes from McDaniel shown in the table at the bottom of the slide.

The next phase of development and actually, let me just mention the capacity of the N05-A platform, 225 million cubic feet a day on a gross basis before any further debottlenecking, we currently using about 1/3 of that capacity. Second phase of development will be the N04 satellite development to the north of the original N05-A. You can see the platform location a little bit better here. N05-A in the blue dot and the yellow dot representing the future N04 satellite platform.

The N04 satellite will be tied into the N05. We intend here to reuse a topside from a decommission block in the North Sea. That platform already identified. We expect to have the project sanctioned in 2026 with the platform probably put in place in '27 and production from development drilling of the N04-A and N04-C pools beginning in 2028. There are also exploration prospects offsetting the N04 platform with Opal likely to be the first one drilled there. And at the bottom of the slide, we show McDaniel's assessment of the volumes associated with these 2 development pools, the N04-A and N04-C that are in the 2P report.

And we detail some of the additional resources that have been identified, estimated on the 5 licenses that come with the GEMS acquisition. Now recall that in the 2P report, there are 3 pools included already, the producing N05-A pool and the tested but not as yet developed N04-A and N04-C pools. These are the ones shown in the red color on this map. Additionally, we have McDaniel perform a resource analysis. These are recoverable -- estimated to be recoverable volumes in the contingent and the prospective categories.

Really, the resource category that's less important to us here is a contingent resource category. Normally, it's listed first, and we follow that convention on this slide. But it's ultimately the prospective pools that are going to be, I think, more important for the longer term. But to address the contingent resource, we'll point out that there are 4 pools included. The bigger of these 2 pool -- the bigger of these 4 pools, the L1 and L2 pools in the Northeastern part of the license area are really too distant to be tied into the N05 or N04 satellite platforms. And along with that, there's 2 smaller pools in the south on the blocks that are included in the continuum category as well discovered, but not of sufficient confidence at this time for development to be included in a reserve category.

In the prospective category, as I mentioned earlier, we -- there were 3 relatively close prospects, N05 Noord, Diamant and Opal that we commissioned McDaniel to do an entire economic evaluation. And those prospects, I discussed earlier in the development phases for GEMS with their combined net value estimated to be around $300 million in the respective category. There are another 11 identified exploration prospects, and these are the ones shown in the light orange color on the map, for which McDaniel conducted evaluations of the potentially recoverable volumes.

And in these 11, they did not take it all the way to an economic evaluation. These prospects are if drilled, are going to be drilled later in time, we believe, than the initial 3. And in a number of cases, they're more distant from the existing and planned platforms and therefore, would require new platforms and infrastructure to bring into production. Nonetheless, those volumes totaling a company net risk mean of around 100 Bcf are shown in this table as well. Again, no guarantees that any of the contingent or prospective resources will be developed. But nonetheless, it's likely, I think, over time that some of this will be drilled. And it's our hope that some of these would eventually get discovered to be able to be converted into a reserve category, underscores the very large long-term potential, we think that exists on this asset base.

We talk about the acquisition price. It's detailed here on Slide 16. It is denominated in USD. These amounts already paid earlier today, October 6. The cash consideration, USD 232 million corresponding at current exchange rates to about CAD 322 million and an additional equity component valued at USD 12 million or CAD 17 million. This is -- will be priced in the -- based on the 20-day VWAP beginning October 6. That amount of shares around 830,000 at Friday's closing price and the actual number of shares to be determined based on this post-announcement and closing average price.

The effective date of the acquisition, December 31, 2024, in lockbox form. Reserves have already been discussed on the lower left, 19 million barrels equivalent at the 2P level with a value of a little bit under CAD 600 million per McDaniel. On the upper right, we point out that there is a contingent component to the consideration. This is based on exploration success. There is an opportunity for the seller to earn up to USD 60 million in -- if 3 discoveries of significant size, 50 Bcf gross or more occur within the next 10 years. There's a small variation on this for one of the prospects, N05 Noord. If it's substantial in size, 50 Bcf, but connected to the existing N05-A pool, then that payment will only be $10 million, in which case the maximum exploration contingent consideration could be $50 million.

This combination of stock and cash consideration yields an estimated flowing production multiple of about CAD 48,000 based on our expected 2026 production. As we discussed earlier, a multiple of about 2x using strip prices on cash flow or FFO and a payout of a little bit less than 3 years on an a-tax basis. The next Slide 17 is really just a breakout of the GEMS reserves, PDP through 2P level and the production profile associated with specifically these pools, these reserve qualifying pools in the McDaniel evaluation.

There is further growth potential beyond just the 3 pools that are in the 2P report. And again, reserves and contingent and prospective resources are very different categories. if there is success in the exploration prospects that are in the prospective categories for the 3 prospects, N05 Noord, Diamant and Opal that were -- had the economic evaluation performed by McDaniel, there is a potential that rates could end up higher than in the 2P report, and that is what is detailed in the plot on the lower right, still staying actually basically within the existing facility capacity with -- unless there's further expansion of the facility capability. So that's kind of the more extended potential picture for production profile of the GEMS assets as envisioned today.

Just to finish off with a couple of corporate items. Let's talk about the 2025 guidance. We first in the upper left detail our activity. We've already done our Canadian drilling this year, the multilateral program that was pretty successful. There are still plans to drill the -- at least to spud the L10 Malachite non-operated development well from our original Netherlands assets in which we have a 21% working interest. Our planned CapEx for the period after the closing of NOBV, we now call this TEN, CAD 55 million to CAD 61 million mainly for well drilling and workover program and the remainder 2 facilities projects. We have a barge moving in now to begin workover activity, and we intend to begin drilling in about the next month or so on an extended drilling program that will go into 2026.

In the case of GEMS, the CapEx that we see for the remainder of the year, about CAD 15 million for beginning of drilling activity and some other facility-oriented projects. Continue to estimate $1.7 million of evaluation capital for the potential CCS project at L10. And of course, organizationally, we continue to evaluate other M&A opportunities. The guidance for the company revised to include GEMS post closing. We rounded off the production impact that would occur from GEMS in the fourth quarter to the nearest 500 BOE/D and added that to the previous guidance, getting us 9,500 to 10,000 BOE/D for the year and added in the $15 million of D&D CapEx to bring us to a total for the company of $100 million to $110 million.

Again, in our financials and what we report as company production and CapEx that is only counted after the closing date. We discussed this earlier when we closed the NOBV or TEN acquisition. Pie chart on the right illustrates the product exposures of the company. Again, this is on a pro forma basis as though we had owned the assets for the entire year, makes us 87% exposed on that basis to TTF gas with the majority of the remainder coming in, in Canadian oil and NGLs and a small amount of AECO exposure. We do continue to hedge, and we are going to lock down a significant amount of revenue for the added production that we're getting from GEMS by hedging activities that are ongoing. We estimate that on this first increment of hedging that we're doing on GEMS that will generate a price of about EUR 30.75 per megawatt hour. That corresponds to about CAD 14.65 per MMBtu, and that will protect around EUR 100 million of revenue during the hedge period for the last quarter of this year through '26 and '27.

And then we do intend to put additional hedges on as the GEMS production goes up. The resulting total corporate hedge position is shown on the graph at right, significant position on for Q4 '25 and the 4 quarters in '26 after that and starting to build a meaningful position in '27 as well. So in summary, as illustrated on Slide 23, we feel that this is a very good acquisition. We feel it's completely in line with the M&A strategy, building on what we had already done in the Netherlands to really create a cornerstone asset base for Tenaz.

This is certainly a high growth, high rate of return asset base. It's meaningfully accretive to our existing shareholders and certainly gives us greater participation in the high-value TTF market. The assets are very strong with respect to what they can generate in terms of cash flow and the free cash flow, putting capital to work to grow the company at a faster rate and build scale in our Netherlands operation. They are ultra-high rate wells. There is a lot of infrastructure capacity that can already be utilized with further drilling. It's certainly very, very high-margin production given that you've got prices in the range of CAD 15 per MMBtu and low royalties and costs that OpEx that over time will probably settle into the range of about CAD 1.5 per Mcf and a significant amount of that cash flow profile already underpinned by our hedging program, which will continue.

In summary, we believe we've got one of the very highest quality, if not the highest quality asset available in the North Sea. It's a state-of-the-art platform, which is placed to top an area with very prospective geology, already delivering very high rates in the existing producer, highest rate well in the Netherlands, a lot of development opportunities that we've detailed here and additionally, quite strong long-term exploration. And we're very proud that the project has been integrated into the renewable energy system as well being powered by the wind farm on the German side of the border.

So in summary, very happy with this acquisition. We appreciate your interest in it, and we look forward to our next opportunity to discuss the Tenaz at the -- at our Q3 release. Thank you.