Recording in progress.
Good morning. Thank you for joining us today for a fireside chat with Alex Verge, Journey Energy's President and Chief Executive Officer. I am Jeff Robertson, Managing Director for Natural Resources at Water Tower Research. Before we begin, I would like to remind participants that our discussion could include forward-looking statements as of today, June 11, 2025. Journey's disclosures regarding such statements can be found under the Investor Relations tab of its corporate homepage. We may reference some slides from Journey's latest investor deck, which is also available for viewing on the company's corporate homepage under the Investor Relations tab. With that housekeeping out of the way, Alex, welcome. Thank you for joining us today.
Thank you very much, and thank you very much to Water Tower Research for hosting this and for allowing companies like ours to have a voice.
Journey is a Calgary-based exploration and production company whose assets consist of conventional plays in the Western Canadian sedimentary basin. Those plays have a resilient production profile and cash flow generation. Excuse me. In addition, the company owns a 30% working interest alongside operator Spartan Delta in a joint venture focused on the light oil window of the Duvernay Shale unconventional play in the Willesden Green area of Central Alberta. The joint venture plans seven gross wells in 2025, stepping up to 12 gross wells in 2026. Early results on recent wells have outperformed the company's type curves, and the joint venture has about 200 remaining gross drilling locations. Journey also has a power generation business under development. First quarter 2025 production averaged approximately 11,000 BOE a day, and the company's full year 2025 outlook is 10,800-11,000 BOE per day.
Alex, I'd like to start with a little bit of background for people who may not be as familiar with Journey or you. Can you just talk about how your journey with Journey started? I think you have about 40 years of experience in the Canadian energy industry.
Thanks very much. Good afternoon or good morning, everyone. Thanks for tuning into this webinar. I've been in the industry over 40 years now. More than 2/3 of my life has been spent working in the energy industry, generally here in Calgary. After working a few summers in the oil industry in the late 1970s, I developed a real passion for oil and gas, and I moved from Toronto to work for Gulf in the early 1980s. When I first started at Gulf, I was working as a reservoir engineer in heavy oil. I was working in around the North Battleford, Saskatchewan office, so I guess probably some of my earlier days was drilling and doing projects, cyclic steaming and things like that in fields like Senlac and Cactus Lake. Those fields are still going.
Those fields are in Strathcona right now, and they were part of Gulf, and then they went to a bunch of different companies, including Oxy and then Northern Blizzard and Kona, and ultimately became Strathcona Resources. They are still going. After about 7.5 years at Gulf in reservoir engineering and production, and then in planning, I went to Shell to specialize in reservoir engineering, and I knew that they had a really great training program. At the time at Shell, it was the first time that I was actually exposed to, rather than just drilling and doing workovers, actually buying and selling oil properties. At Shell, it was mostly selling, but since then, it has been mostly buying since the mid-1990s, and that has been at POCO, and then at Bonavista, and then at NuVista, and now Journey.
If we talk about Journey, as you joined the predecessor company and acquired the current asset base, were there key attributes of properties that you were looking for based on some of your prior experiences with Shell and Gulf?
Yes. After I left NuVista, I was looking for something to do, and Patrick Samson, he was a portfolio manager at PSP, which is a large pension fund out of Quebec. He got me to join the board of Sword Corp, which was Journey's predecessor, and he asked me to help him out. When I joined the board of this company, they had a number of pools in the Pembina area, in the Cardium, and in the Matziwin area in the Glauc, where we began drilling horizontal wells for oil. These horizontal wells were really breathing new life into some of these older pools. Back then, you know, multi-stage fracturing was relatively new, and we decided as a company. I took over the company in 2012. The pension fund put a little bit more money in, helped us get a head start drilling these wells.
We restructured the company. We moved some assets to the side and ultimately disposed of them. Long story short, we decided as a company to focus on shallow to medium drilling. I'm going to say it's probably in the 3,000-3,500 ft range. The reason for that is that we wanted each single event.
Each single event.
I'm getting a bit of an echo. Is this my issue here? We didn't want any single event to kind of derail the company. We wanted to make sure that we could keep our exposure costs low. We wanted to drill these wells that were kind of in the medium depth range. At the time, WTI was trading at about CAD 100 a barrel. The industry cost structure was lower, and there were a lot of these underexploited assets that existed. It was easy to get it. Shale gas was just beginning to really take hold down in the states and things like the Barnett, but the shale oil wasn't really a big thing back then. Back then, the focus on end-of-life costs was also diminished as well.
Alex, as you moved the portfolio around, was some of that driven by a preference for a certain commodity, or was it more just trying to find the asset that could generate the best rate of return and cash flow for the company?
Yeah, I've always believed, if you look at sort of NuVista's history when I was there, I've always believed that you kind of grow these companies from a small size through kind of buying and exploiting assets. Then when you get to be a little bit larger, you start to move into more of the repeatable plays. The industry has completely shifted over the last few years. The reason that it shifted, I think, is because commodity prices have been fairly low. There has been a continued focus on repeatable plays and plays that can generate high returns, quick paybacks, and less focus on things with kind of a lot of moving parts. As a company right now, Journey is now blessed with kind of both of these things.
I mean, we have conventional assets that contain a billion barrels of oil in place, and we have also this emerging repeatable play as well.
Let's touch on the asset base, but before we start talking about the Duvernay, I'd like to maybe spend a few minutes talking about the current assets, such as Medicine Hat and how they fit in the company's portfolio. Can you talk about the upside opportunity at Medicine Hat and what oil prices are needed to support further development and exploitation there?
Sure. Like I just mentioned, our conventional asset base contains about a billion barrels of oil in place. Like I said, our flagship conventional asset, as you mentioned, is this Medicine Hat Glauc Pool. We acquired a 72% interest in this pool, and we operate it at the end of 2022 from Enerplus. The pool itself is a Glauconite oil pool. It contains 310 million barrels of oil in place. It does trade on a WCS basis. The infill drilling in Medicine Hat is extremely attractive. Almost all of the pool is drilled using horizontal wells on water flood, but we probably have about 30 locations left. We are talking about rates of return of probably over 60% and payout periods of under two years, even with prices in the CAD 60 range. As you know, we have come up a little bit from that recently.
We have two large polymer blending facilities, one in the north of the field and one in the southern portion of the field. Though I don't know how much those facilities would cost, they probably cost CAD 30 million-CAD 40 million to build at the time, but they'd probably be more like CAD 60 million to build today. Those facilities will ultimately let us expand the polymer flooding portion of the field. About 20% of the field is under polymer flood right now, and we hope to, over time, over a longer period of time, to expand that to up to about 75% of the field under polymer flood. When I look at Medicine Hat today, and I know Journey's trading at a relatively low valuation, our PDP blowdown value of just producing out those reserves in Medicine Hat is probably equivalent to our current market cap.
If we add the development wedge associated with the 34 infill wells that we have in our reserve report, that pretty much equals our debt. If we look at the unbooked polymer upside, we have the potential to keep this thing flat at around 1,500 barrels a day, probably into the 2040 time period. The thing I really like about it is if you buy Journey's stock, you're basically paying for Medicine Hat, and you're getting everything else free.
You mentioned the production profile of Medicine Hat. With an asset base that has a lot of long-lived, established, predictable production, can you talk about the cash flow profile that those assets generate for the company and how that supports this funding for the Duvernay development program that you're embarking on?
Yes. Thank you. I think it's a great question, and I think it's a pretty important concept. The blowdown value of our assets, so basically if you look at our reserve report and you use forecasted prices and you just produce out the assets with a 90% confidence level, the blowdown value of our assets is about CAD 350 million. Now, asset prices in Canada are somewhat depressed. Sometimes assets trade at less than their blowdown value. Let's say that given the uncertainty in the medium term around commodity prices, you could get two to three times operating income for that asset base. In the case of our assets with such a low decline, our PDP value is a higher multiple of operating income.
Long story short is let's say you could sell those assets for CAD 150 million today and just focus on the Duvernay and be a pure play. That gives you CAD 150 million to plow into the Duvernay. If we just produce out those assets, even with all of our liabilities taken into effect, even with everything else kind of done, if we just produce out those assets, we're going to get CAD 350 million of cash off that asset base just to put back into the Duvernay. You're going to get a lot more cash. If we selectively do the exploitation projects on those, our 2P value on those assets is over CAD 700 million.
You're going to get way more value with this stable long-life asset base using the free cash flow from that to develop the Duvernay and combining the two assets into one company than you would if you just sold the assets and became a pure Duvernay player, no matter how good that Duvernay play is.
Alex, let's touch on the power business for a minute. Journey has two natural gas-fired power plants that are going through refurbishment and are expected to come online in the next 12 months. Power prices have been volatile in Alberta over the last couple of years, and I think that it's part of the strategy of why you all decided to get into those businesses. Can you just expand on the strategy behind your exposure in the power business? Then secondly, are there any constraints on key equipment or permits remaining to be able to bring those plants online?
Yeah. The power business for us has been kind of a love-hate kind of relationship here. The power business, we got into it at first with our initial 4 MW power plant that we built in the Countess area of Alberta. We had a lot of shallow gas in that area, and we decided, hey, we could maybe cost-effectively build a power plant, sell the power to the grid, and kind of extend the life of the Countess shallow gas. We brought it on in 2020. Between 2021 and 2023, our power prices in Alberta went through what I would say is a real big spike relative to the historic values. During the peak of this price spike, we experienced inside Journey significant volatility in our fuel and power costs.
Not only was Countess making a lot of money, and Countess is now already fully paid out and it's still going, but at the time, up to 25% of Journey's operating cost is fuel and power. If we look at 2022, which is kind of the peak of the peak, our power bill in one month in 2022 was CAD 600,000. In another month, it was CAD 3 million. In 2020, our power bill was under CAD 5 million, which is where it kind of is today. In 2022, our power bill jumped up to about CAD 22 million. With that kind of volatility, it was extremely difficult for us to plan. We use a lot of power for a lot of the assets that we produce because we've got a bunch of pools on secondary recovery. We inject water. We use a lot of power in the field.
Because of that, our view is that, hey, if we could build enough power projects and connect them to the grid, the power that we sold to the grid would offset our fuel and power costs, and it would create more sustainability for the company over the longer term. We embarked on the process of these two projects. We use new equipment, like relatively used equipment, but it has low hours, so it is almost like new equipment. We have been kind of finding these units, cobbling them together, and then building power infrastructure where we are at, and then trying to connect these projects to the grid. In one case, that is what we did up in Gilby, where we got units from other places and have been building this thing from scratch.
In another case, we bought a project that was discharging power to the grid, fully functional and operating, and was shut in by the AER about six or seven years ago. It only ran for about a year, and it was built at a cost of over CAD 31 million. Like I say, over the past few years, as we've been in this process, we've invested close to CAD 30 million on these two projects at Gilby and Mazeppa, and they should bring on about 30 MW of power. They're costing a little bit more than originally budgeted due to higher grid connection costs, and there have been a lot of delays with respect to the regulators. When this is coming on the grid, they're literally about two years behind schedule. The regulatory process has been challenging.
We're nearing the end of these challenges, but it has been difficult for us. We thought things were going to happen faster, come on sooner, maybe even cost less to get these things connected to the grid, but they've been costing a little bit more to get connected to the grid than we first budgeted. Further to this, in 2024 and 2025, power prices have kind of come under pressure. They've been at historic lows, and prices are forecast to stay low maybe in 2026. We have an excess of power in the project in the province for probably a short to medium term. Because of this, our Countess power project is only running at about 1/3 of the time.
Even if you look at all of these trials and tribulations internally, Journey still feels that our entry into the power business is the right thing, and it's going to yield substantial value over time. It's more difficult to quantify that value in the context of the current market and where power prices are, but it's really difficult to get these things on the grid. Once you have something that is difficult to get more of, it becomes more valuable over time. That's my belief with pipelines, and I believe power projects fit into the same thing. The power market is extremely volatile. I think it's going to become more volatile, and the fact that these are reciprocating gas units that can be turned on and turned off daily if they need to.
That allows you to participate in ancillary services as well as the sale of energy. At the end of the day, I think that the jury's still out as to how much value we're going to create with these things. Literally, that CAD 30 million, or call it CAD 0.50 a share, that's already sunk. It's not in any of the valuations. As these things come on, they're not going to decline, and they're going to contribute years and years and years of positive cash flow that we're going to use to deploy into other parts of the business. They're going to make the company's operating costs more sustainable in periods of extremely high power pricing.
If I think about it in the context of what you just said, that basically the value to Journey is a bit of a hedge against operating costs, which ultimately could increase the returns or the cash flow capability of your producing oil and gas assets, that that ultimately is the long-term value proposition for being in the power business. That is exactly our summary.
Exactly. They've been consuming money and consuming money, but now they're going to start to actually generate revenue, which is going to go for these are 20- or 30-year projects. I don't think we're going to determine what the ultimate value of these things is based on one year of fairly low commodity prices. Because of where these things sit in the approval queue, because we've been kind of going down this approval road for years in the case of both of these projects, most of the remaining costs in these are associated with grid connection costs and startup costs and commissioning of the projects. Because of that, over 70% or 75% of the capital has already been spent. The money's already been invested.
Now we can't really change the timing of anything when the grid is ready to receive these projects and whatever Fortis needs to do to put in power poles or more power lines. Whenever that's all done, these things are going to come on. We've got an initial start date on the Gilby project for October of this year. We've got an initial start date on the Mazeppa project for June of next year. These initial start dates have been sliding over time as the regulators have been a bit slower, and they control those initial start dates. The closer you get, the more difficult it is to move those things into the future. We're almost there on both of these.
Let's shift to the Duvernay, which is expected to drive production growth and cash flow growth through the end of the decade and into the next. Can you give us a little bit of background on the play and how Journey got involved and what really attracted you to the play and in particular to the acreage that you're involved in?
Yeah. I mean, we're extremely proud of what we've done with the Duvernay, especially for a company our size. We're an early mover in the play. We purchased some assets in the Gilby area, including power plants and some Glauc gas from a company called Predator. These were formerly Mosaic assets. I believe we purchased these assets in 2017. Mosaic had some Duvernay land. It wasn't exactly in the right spot, but it led us to start looking at the Duvernay. Back in 2017, we began mapping up the Duvernay. And really, we zeroed in on our acreage. How am I going to say it? Okay. I'll just give you the history, and then I'll talk about how we kind of decide on the acreage. There was a number of people that had put a lot of money into the Duvernay.
These resource plays tend to go through multiple rounds. You had big players like Repsol and Encana and Shell, and they were buying land for huge amounts of money and testing the Duvernay. Some of that land was turning out to be gassier than other parts. The way we entered the area is we mapped the whole play up in 2017. We identified some Encana lands and some Repsol lands as the sweet spot of that play. The way we did it is Brett Boklaschuk, our VP of Exploration, he originally mapped this fairway. He identified the reef structures to the west. There is a slide in our presentation, slide number 11, which kind of has an orientation map on the play.
In that slide, you can see the reefs in purple kind of cutting across from the southern portion to the northern portion on the east side of the map sheet. The view was that the reefs over geological time acted as a cooling mechanism. Therefore, the closer you were to the reefs, the more likely you were to have oil. The further away from the reefs, the more likely you were to have gas. The way I kind of look at it is that you do not want to be too close to the reef because you have too much carbonate and not enough shale. It is kind of a little bit of a Goldilocks scenario here where we focused on lands in a narrow fairway parallel to the reef trend.
We were in the thickest reservoir, the most shale, and the most likely to have the oil. We identified that Encana had a bunch of lands in here. These are a mixture of freehold lands and crown lands. When I looked at it, it was kind of like a checkerboard where the freehold lands would be in red, and they were controlled by Encana. Repsol had bought the crown lands, and they would be the black squares in the checkerboard. The two of them had never really got a deal where they agreed. You had this checkerboard stalemate, and everyone wanted to drill two-mile horizontal wells. We purchased the Encana lands.
As soon as we purchased the Encana lands, Repsol said, "Okay, fine, you can have our lands too." For about CAD 5 million or CAD 6 million, we had accumulated 100 sections of Duvernay land that we thought was kind of right in the sweet spot. At the time we did this, there were companies out there like Resourceful that were drilling Duvernay wells, and they were costing more than CAD 20 million each. We are a small company, so it was easy for us to take a CAD 5 million flyer on land knowing the potential of the play. It was really difficult for us to consider exposing CAD 20 million on a single well. We had the land. It was good land. We thought it was in the right spot.
The problem is that we only had about four years of tenure on the Encana lands and only about two to four years of tenure on the Repsol lands. We had to start drilling this play, and we had no way to fund it on our own. We did not want to bankrupt the company drilling these crazy wells. The land was worthless until we entered into a joint venture. We entered into a joint venture with a company called Kiwetinohk. We spent about eight intense months looking for funding options for the play. That resulted in this Kiwetinohk joint venture in 2018. With full earning, Kiwetinohk would have earned about 62.5% of the Duvernay lands. We would have went down to about 37.5 net sections.
The reason I say that is because we're almost at the same point again now after everything that happened. In 2019, Kiwetinohk had spent a lot of money on the wells. We think they overspent. They spent CAD 75 million in total on all of our lands. We felt that they failed to execute. They did not drill the wells the optimum way we wanted to. They drilled three of the wells in the right spot. We did have three wells now on production. Over time, these wells have proved to be extremely encouraging. In 2020 and in 2021, during COVID, Kiwetinohk was not spending any money on the land. Journey was in no position to spend any money on the land. Basically, the industry fell in hard times during COVID.
Most of this land went back to PrairieSky, who is the lessee on the freehold, and expired and went back to the crown. By early 2023, we were down to about 19 sections. Five of those 19 sections were kind of in the more gassy portion in the northeast part of the play, and they were set to expire. Back then, we said, "Okay, what if we sell those lands?" We did. We wound up selling those lands to Bonavista at the time. Kiwetinohk, who was our partner, actually exercised the role for and bought them. We wound up selling those lands, and we took the money, and we gave the money to PrairieSky.
We said, "We want to release some of the key lands in the middle of the play between these three basin-leading wells." Here we are in kind of 2023, and now we've got about 30-35 net sections. Kiwetinohk sold out to Spartan Delta. Spartan Delta started buying all the land around us. Spartan Delta did a big deal with Bonavista to the north, basically started accumulating all of this land. They did a big farm-in with PrairieSky and all of the other lands that we didn't get. We were kind of in there and mixed up with Spartan Delta. Some of our joint venture lands that we had with Kiwetinohk were lands that Spartan Delta now owned and controlled. We had some of the sweet spot lands on our own, and Spartan had some of their own lands.
We said in May of 2024 that we started talking to Spartan about pooling these lands together and creating this joint venture. We were able to pretty much define the boundaries of the joint venture and keep those boundaries inside that sweet spot that we had mapped up and identified. That sweet spot that we identified in 2017 is still the sweet spot today.
You talked about the evolution of the plays, like a lot of the resource plays in the U.S., where early on, companies go and lease every acre they can find that they can call in a play, like the Barnett or the Haynesville or some of the other shale plays that have evolved, and then figure out later through drilling what the sweet spots are. It sounds like you all did the technical work upfront based on your interpretation. And with the drilling that you show on slide 11, where you've got wells to the south, to the north, and to the west of you, that has proved correct in your interpretation. Is that the right way to think about it?
Exactly. If we look at slide 11, it's kind of an orientation map. What I'll say is that you had companies like Raging River and Crescent Point that were competing to the north of us. You had Repsol, and you had Paramount to the south of us. We had some lands in the middle. In 2020, activity kind of slowed down, and lands expired and changed. Sometimes these plays go through two or three different iterations. Initially, they went drilling for the sweet spot further to the west. The wells were really, really gassy. Then they kind of honed in on where they were. There was a bunch of different land grabs. Some guys failed. Some guys did not. Costs were higher. They were not really completely dialed in. The play went through a bunch more iterations.
What you're seeing in slide number 11 is where we're at now. You have Baytex in the north in sort of a khaki color. You have Paramount to the south in kind of a red color. You have Spartan Delta lands in the gray, which are around the joint venture block. You have the joint venture block there in the orange. Spartan Delta not only has the gray lands around it, but they have 70% of the orange lands as well. When you look at it now, we're down to kind of three or four key players on this trend. If you look at the purple lines on slide 11, those are the wells that have more or less been recently drilled. You can see Baytex has drilled, I don't know, 50 wells. Paramount's drilled 50 wells.
They're each drilling 20-30 wells a year. You can see that Spartan has got some wells in the north that they drilled from Bonavista on the Bonavista that they got from Bonavista. They have some wells that they've been doing on their own acreage that they've been drilling. You have the joint venture drilling. There are more than 100 wells in this trend now. We're gradually really dialing in the technology on this. I mean, maybe it is now a good time to maybe just talk about sort of the type curve and the performance of some of our wells. What do you think, Jeff?
Yeah, I'd be curious. Two things on that. One is the orientation of the wells on your joint venture land with Spartan Delta is essentially northwest to southeast. The wells to the north of you look like they were drilled more in a north-south orientation. Can you talk a little bit about the orientation? Secondly, you show on the slide that some of the recent wells have outperformed some of the original type curves. I'm just wondering what has changed either from a drilling and/or a completion standpoint that you've learned that contributes to the improved performance?
Fantastic. Okay. Interesting ongoing debate. Bonavista drilled north-south. Baytex drills north-south. If you kind of look in Alberta at, in general, the stress planes are parallel to the source to the mountains. Call it northwest to southeast. The natural orientation is generally 90 degrees perpendicular to that. If you drill on azimuth wells, basically on the angle that we are drilling them, the fracts in the well should be basically at 90 degrees to the well. You get the most even type of fracturing. If you drill on kind of a northwest orientation, your fract plane is kind of on maybe a 45-degree angle or a little bit less than a 45-degree angle to where the well is. If you drilled the wells opposite to the way we drilled them, your fracts would be along the well, and they would all kind of connect.
The natural tendency of these—in general, even in the Montney, you generally see some operators drilling these things north-south. The reason you drill them north-south is because you can usually get—because your land deals, and you have two sections of land, you want to drill four wells. You do not have the ability to drill them this way. You need a large contiguous block of land if you are going to develop a whole block of land basically on azimuth. You need only two sections if you want to drill north-south. Depending on how your land is shaped, you can do that. We have had discussions with companies like Baytex. We do trade a lot of information around. I do think the on-azimuth wells could be up to 20% better than the wells north-south.
If we look at slide 11, and we look at the type curve, and we talk about these wells, you're going to see three things on that slide 11 in the type curve. You're going to see three gray lines, which are the first three wells. If we went to slide 10, if we went to slide 10 in the presentation, I think you have a more detailed map of where our wells are. You'll see three black lines on slide 10, which are the original three wells kind of right in the middle of our joint venture. Those are the three wells that are in the type curve on slide 11. Our old type curve went right through those three wells. After these wells were drilled in the fall of last year, and they came on in the beginning of December, the two new wells.
Again, jumping back to that slide number 10, these wells would be called one and two. They are described as one and two on slide number 10. After we drilled those wells and brought them on in December, it looked like they were doing so much better that we decided to increase that type curve. We increased that type curve by more than 10%. These wells are continuing to outperform that new type curve. Our type curve basically is better than before. We think that over time, you are going to have some parent wells and some child wells. We think that our type curve is maybe on average the best representation for the total play. We think the unbounded wells could be a little bit better than the type curve, and the bounded wells could maybe be a little bit worse than the type curve.
We think we are fairly comfortable that we are going to get this on the average. That is extremely exciting because the early rate performance of these wells is tremendous. If you want to figure out why these wells are better, I mean, here is what we thought. We are now drilling these wells, we are using more clusters per stage, so more sets of perforations for each individual stage. We are using higher sand concentrations per barrel of water pumped. Essentially, we are pumping the same amount of sand in these wells as the original three wells, but we are doing it at lower rates with a third of the water. What this is doing is it is giving us smaller height growth.
It's interesting because in the Montney, where the reservoir can be up to 100 meters thick, guys are going away from this kind of completion program, and they're going into more limited entry type programs like NCS fract systems and things that have more limited entry in order to get more height growth in the Montney. In the Duvernay, instead of being like 100 meters thick, the Duvernay is 40 meters thick. What we think happened originally is that they got too much height growth, and some of that energy went out of the reservoir. The Duvernay is, like I say, 40 meters thick. Let's go 120 ft thick shale zone. We thought the new wells would be better than the old ones, but I think we're really, really surprised at just how much better that they are.
You've drilled, I think, eight gross wells this year. Can you talk about the completion schedule of those wells for the balance of 2025? I would like you to just touch on how you think the growth profile of this play will develop over the next several years. I would point people to slide 12 in the deck that shows the development of the Duvernay out through the end of the decade and into the next.
Okay. I'll start with slide 10, and then I'll move to slide 12. Slide 10 kind of gives you the development plan for this year. There are two numbers, one and two, on slide 10, where, like I say, the two wells that came on in December were that are on that type curve. Circle number three on slide 10 has a three-well pad. That three-well pad was drilled, and those wells have been completed, and those wells have come on. Two wells have been on longer than one of them. One of them just came on within the last couple of weeks. Two wells have been on for close to a month now. We haven't really released any data on those wells, but you're going to be seeing it very soon. Those wells, like I say, are already on production.
The wells where the number four is, that is a four-well pad. Those wells are in the process of being completed right now. Those wells, I would say they are 80% completed. We are more or less—well, we are probably 75% of the fracts are done on those wells. Those wells will be completed by the end of this month. Plugs will be milled out. I am not sure that all four wells will come on in early July, but there may be two in July and two in August. Long story short, we have two on, and we have had them on since December, three more have come on within the last month. Two more will be coming on in July at least. By August, all seven of those wells will be on. There is also on the map in slide 10, a green well to the very north.
That's a duck that we drilled in the first quarter, and it will be completed and brought on as part of next year's program. When we look at the program, the reason we're doing it in the way that we're doing it in is if you look at the availability of water, you have a lot more water available in the spring. It makes sense to drill these wells in the first quarter or the first four months of the year and then complete them all in the spring to front-end load the program. When you talk about this front-end loading of the program, that's what you see on slide number 12. You can see these programs being front-end loaded where they're drilled in the early part of the year.
They're completed in the spring, and they're brought on kind of in the middle of the year. That's what you're seeing for 2025- 2030 in the slide on page 12. Again, using that same similar type curve, the wells are doing better than that, but not all of them will. We're using that same type curve as an average. When you look at that type curve, I mean, or I mean that production forecast, it kind of ramps up to about 8,000 barrels a day. In 2030, it probably averages closer to 6,000 barrels a day. By 2031, it'll probably be averaging over 8,000 barrels a day. The peak in one year is kind of more or less the average in the following year. These things are kind of ramping up. What's in that assumption is the seven gross wells.
Remember, we have a 30% interest in all of this. We have 200 gross, 60 net wells to drill. This year, seven gross wells, 2.1 net. Next year, we have assumed 12 wells, which is 3.6 net, and then 16 wells per year, every year thereafter, 4.8 net. If you kind of look at that, it is like a CAD 1 billion gross capital outlay, CAD 300 million net development during this timeline on just the JV lands. It is a huge project. It is going to consume a lot of our capital. The interesting thing is if you get out to 8,000 barrels a day and you apply the netback, we are using a CAD 47.50 netback over the five-year period, which is kind of the netback in the reserve report over that period.
If you apply that netback to 8,000 barrels a day, it's about CAD 140 million of incremental operating income. I mean, obviously, anything like this, it's got a tremendous amount of assumptions on it. Like I say, the type curve is one assumption. The pricing is another assumption. Realistically, I think this is a very plausible development scenario for this existing play. I think the new wells will hopefully support the type curve and continue to reinforce. Eventually, the market will start to realize that this is a true reality of the future for us. As a small company, this is hugely meaningful. Another thing to add is that if you add up all those wells, 16 wells a year, and then 12 wells next year and seven this year, it's about 83 gross wells. Like I say, we have 200 to drill.
Even by the time we get out to this development plan, we're nowhere near done. We're not even halfway done on developing the JV lands.
Alex, with the type of netback you described, is this play very sensitive to commodity prices? I mean, I know, obviously, you've got to fund it. So cash flow is important.
Yeah. I mean, the beauty of this play is it's exactly the things that we don't tend to have inside the company. These wells come on at tremendous rates. The rate of return for each individual well is obviously sensitive to pricing in the first four months because they produce like 100,000 barrels in the first four months. Because they pay out so quickly, I mean, the payout period appears to be less affected than the cost. Just to put it in perspective, if you spend CAD 30 million drilling and completing wells like we're doing this year, you're going to get CAD 20 million of that CAD 30 million back in the first six months. They take a little bit more time to pay out because, obviously, there's a big decline profile here, and they decline off.
The return and the recycle of cash is so fast that it makes this play unique and very different from the other plays that we have in Journey. It's kind of just what we're missing.
Is there any additional acreage within your JV area with Spartan Delta that's available?
Yeah. Before we did the JV with Spartan, when they were buying land and we were buying land, there was a great big land sale on March 20th, 2024. We actually went to that land sale but did not get any land. Spartan got some of the land. Baytex got some of the land. In that sale, the value of this land was established at kind of more than CAD 1 million a section. As you can see on that map sheet, a lot of the lands are pretty concentrated into those bigger players right now. I know that CAD 1 million a section is pretty low compared to a lot of the U.S. plays, but it is pretty high for Canada. It demonstrates how competitive this area is becoming and this play is becoming.
I would say that growing the play 15%-20% in the medium term might be kind of possible by filling in the holes that exist and buying some land around the edges and moving to the west a little bit. I think in the current sweet spot with the existing players, it's highly unlikely we're going to double the size of this play. I think this play will eventually move to the west, but the wells will be gassier there, and they won't be quite as economic as the wells that we're looking at right now.
If we shift gears and talk about financials, Journey completed a refinancing in March, which turned out some of your debt, refinanced term loan, and put in a new credit facility with a commercial bank. Can you talk about how you think about the company's leverage profile, and do you have long-term leverage targets in mind?
Sure. Thank you. Great question. The financing was completed in March. We've been trying to get a bank line since 2020. At the end of 2020, we wound up buying out our existing line of chartered banks at somewhat of a discount with the help of AIMCo, who's our largest shareholder, and at the time held all of our debt, which we've now paid back. We wanted to reestablish a banking relationship since 2020.
It was not until the results of the Duvernay came in and they started to see the results of the Duvernay that they started saying, "Hey, maybe we should back Journey because Spartan's going to be expansionary in their plan, and we want to make sure that Journey has the money to fund Spartan, and we really like the play." As part of this financing, the bank wanted us to pay out the remaining AIMCo term debt. It was only like CAD 10 million or CAD 12 million. There was not much left. That is all we have drawn on this bank line to this point, call it CAD 10 million or CAD 11 million on the CAD 55 million kind of series of debt tranches. It also includes an operating line and a separate tranche solely for Duvernay capital expenditures.
Why do we think this is the best kind of financing for us? I think if you look at, like I say, what I mentioned earlier on the development plan and the water flows, there is a huge benefit to drilling these wells in the first quarter in terms of social license, in terms of water handling, in terms of everything, and then collect a runoff in the first part of the year in the spring and then frac them in the spring. You are front-end loading the capital in the first half of the year, and then you are paying back a large portion of that capital, more than 50%, maybe even 2/3 of that capital in the second half of the year.
If you look at this, the quick payout of the Duvernay means you ramp up capital in the first half, pay it back. That is why this RBL is great. You are not getting a term debt that is lasting for a fixed period of time. We are hoping that when the results of these wells are in, we will be able to convert this to one kind of RBL line, draw on it in the spring, pay it back in the fall. Leverage is going to be a little bit lumpy because of the nature of the Duvernay capital expenditures. As far as our term debt, we did a CAD 38 million convertible debenture in March of last year. That pushed about 60% of our debt at the time or 65% of our debt out till March of 2029.
Over the long term, I think the leverage ratio is important. As 2020 showed us, it is kind of who owns the debt, what your relationship is with that owner, I mean, and what the covenants are and how fast you have to repay it. That is equally as important as the leverage. I would suggest that we would always want to be in the 0.5-1 debt to cash flow range. I would say 0.5 is our target, but maybe willing to go up to 1 in the height of the Duvernay expenditures and then back down to 0.5. I kind of think that is the sweet spot on leverage for us. Based on the results of these wells, I am hoping that we will get an RBL from the banks on the whole tranche in the fall.
Every year, based on the results of the wells, maybe they'll actually increase that and allow us to run kind of larger and larger, more expansionary programs as we really start rolling in this play.
When you look at the cash flow growth profile of the Duvernay, Alex, and the capital allocation priorities of Journey, does the Duvernay and the potential returns in the Duvernay, does that crowd out allocating capital to some of the longer-term mature assets like Medicine Hat? Or is there room for both? And then do acquisitions fit in there somewhere?
Yeah. I mean, we've been a buy and if you look at Bonavista, NuVista, Journey, all the companies that I've been associated with, there's always been a buy and exploit stage. Then gradually, in the case of Bonavista, they moved to a repeatable play in the Glauc and the Hoadley. In the case of NuVista, we moved to the Montney. In the case of Journey, now we're moving to the Duvernay. Probably we're going to need another one inside Journey at some point, another resource-type play. When I look at it, I do believe that acquisitions can be an important part of our business. The Medicine Hat acquisition in the summer of 2022 and closing in the fall of 2022, that was a great piece of business. It made the company better. It dramatically increased the net asset value of the company.
I think those acquisitions are important, but you really need to do them when your house is in order. You can push out term debt. You can draw on an RBL. You can raise some equity. You can cut your capital in order to accommodate an acquisition when it arrives. They're lumpy, and they come when they come. We did all this with Enerplus. With the Duvernay now, the difference between where we are now and where we were before is because we do not operate, because we are a smaller piece of a bigger pie. We do have less risk in any one single event derailing the company. What we gave up is control over the capital spending and that profile. We need to keep up with our partner in terms of funding this ongoing development.
We cannot just say, "Hey, I'm going to stop spending money on the Duvernay in order to digest this acquisition." Because we do not operate our capital program, it is going to be really hard or impossible for us to find an acquisition with a rate of return, a payback period, an operating income multiple, you name it, that is superior to the Duvernay. If an opportunity presented itself and we could stop the Duvernay spending and do the deal, we might do it. Because we cannot, it is probably less likely that we are focusing on that kind of thing. In terms of any other kind of deal, I think the Duvernay capital comes first. We are still going to be spending money in Medicine Hat. We are still going to be spending money in SCIF. We are still going to be spending money in our conventional assets.
Again, Journey always just, we get into reduced cash flow because of a drop in commodity prices, or we buy something, or we do something. We just stop spending money. We can't now. So the Duvernay has to come first, and then everything else kind of comes second.
A lot of companies, obviously, return cash to shareholders through dividends and repurchases. If we think about Journey today and the value creation opportunity that you think you have, can you talk about the trade-offs between returning cash to shareholders versus investing in the asset base to grow, especially the Duvernay program, and capture and bring forward the net asset value opportunity you have there?
Yeah. I think I kind of refer to another slide in our presentation, which is kind of tricky to explain, but it is a slide on slide 9, where we try in slide 9 to explain what is going on with the company or why we trade at such a big discount. The moral of the story is most of the companies here in Alberta right now in the current commodity price environment are trading at about, give or take, three times operating income. Your reserve value is one thing, and your operating income is another. If you have a really flat decline profile, you have a long, long life reserve index. Your net asset value is a larger multiple of your operating income than if your assets are dropping kind of really quickly.
Because our assets are worth about 4.5 times our operating income in terms of the produce-out value, whereas the industry average is only 2.5 times, we trade at a huge discount to now. You have the one factor that you trade at this big discount to your net asset value or your blowdown value of your assets, but you trade on a competitive basis in terms of your operating income multiple. I mean, Baytex would be an example of this where they have a much larger decline than we do. Their corporate decline is probably over 30%. We actually trade at a premium to them in terms of a multiple of our operating income, but they trade at 1.3 times their PDP, and we trade at 0.5 or 0.6 times our PDP.
The reality is, in our view, now, each of these affects both, but share buybacks, in particular, they tend to affect the net asset value more than anything. We are trading at an undervalued level. Shares are really cheap. You can buy back your shares and increase your net asset value. I mean, our net asset value is so high relative to where we are trading at right now, I do not think it makes much of a difference. Whereas if we are drilling these Duvernay wells and bringing on huge operating income very quickly, and we are ramping up that operating income, we think that is the best way to move the needle and to improve our cost of capital over time.
In the near term for this year and perhaps the first part of next year, while we're going to be struggling on our very own to keep up with the pace of development with Spartan Delta, most of our capital is going to be going into this growth capital to basically accelerate our operating income and kind of help us trade into our NAV, so to speak.
Alex, if you did have a spike in oil prices that triggered a windfall in cash flow compared to where you sit today, would that incremental cash be directed toward the Duvernay, do you think? Or would you have anything else in mind?
Yeah. I mean, I think if we were anxious to ramp up the Duvernay, I think Spartan might kind of be more than amenable to go faster. I mean, if we want to ramp up the Duvernay, but they have some Duvernay drilling on their own lands, they have some Duvernay drilling on ours, they have some conventional drilling, if they have their own priorities, they may not want to do it. It is something that, in general, we do not have a tremendous amount of control. If we did have a price spike or something, I mean, I guess there are a bunch of ways that you can get incremental windfall of cash. You could sell an asset, or you could get a price spike.
If we were to do something like that, depending on where our stock is, if our stock is where it is today, I think the very next thing that I would want to do is buy back some of those shares with some of that money. Even though it's just working on NAV, it is making us more efficient on a per-share basis. If we did sell an asset and the stock hadn't really gone up that much, I would put some of that money into share buybacks. If it's a big price spike and the price has gone up, then maybe the shares have already gone up, and maybe that doesn't necessarily make as much sense. The next source I would do is I would probably aggressively spend some money on our existing assets.
The thing is right now, we're spending our money on our Duvernay, but we're not spending our money on our existing assets. Spending money on your existing assets is kind of a no-brainer because you're adding production to underutilized facilities that's coming on a very low operating cost, and it's improving the sustainability of the company. First priority, and I'm assuming that the power projects are now done and on, and they do not need a lot of capital. First priority is the Duvernay. Second priority, I guess, would be a share buyback unless the share price has changed a lot. Third priority would be kind of spending some money on our conventional assets. By the time 2028 rolls around and these projects start to crank out more money, we probably have enough money to do everything.
At that point, then you would look at maybe returning capital to shareholders in the form of a dividend.
Before we wrap up, I would like to touch on politics. Have any of the actions taken by the Trump administration, or has any had an effect on Journey? Secondly to that, Canada elected a new Labour Prime Minister a couple of months back. Are there any changes in the political landscape in Canada that affect what Journey's doing in Alberta?
No. I mean, I think Liberation Day in early April affected industries on both sides of the border in terms of perhaps increasing costs of things like steel and capital costs, but primarily by the drop in the price of WTI. Over a one-week period, the U.S. dollar dropped by close to $10, which for Journey means a CAD 20 million reduction in our cash flow. The thing is that all of our capital's fixed and all of our capital's front-end loaded. Basically, what it means is that, hey, you're going to spend this much money this year. If you got less cash flow, you have higher debt at the end of the year. That's just the math. That clearly has an effect. Now, most of that has come back in the recent week and a half.
I mean, maybe this is just short-lived, and maybe we're going to come back to where we were. I mean, our budget was CAD 72 oil. It went as low as CAD 60, and now it's back up to CAD 66. Hard to say. The other thing that affects us in the negative is kind of the U.S. dollar. The U.S. dollar has actually dropped relative to the Canadian dollar because of the impact of the tariffs. Now that there's deals with China and all this stuff, maybe that'll kind of work its way through.
The other thing is that as we drill more Duvernay wells and as more of our production becomes Duvernay, and as the Duvernay has three times the netback, lower operating costs, lower royalties, and the rest of our production, as this all happens, that is just going to increase the sustainability of the company over time and make us less affected by these huge swings in commodity prices. That is probably a few years out. In terms of the Canadian election, yeah, we just elected kind of our fourth Liberal Prime Minister in a row. Alberta is primarily conservative. Alberta feels that we have had kind of a rough go over the last 10 years with the existing Liberal governments and their energy policies. What I will say about the Canadian oil industry is that we are a kind of resilient bunch.
You throw stuff at us, we buckle down, and we deal with it. That said, kind of need consistent rules that we can identify and understand. I would like to see rules that apply equally to small guys as they do to the giants because we tend to listen more to what the giants want and not as much to the smaller producers. The other thing that we need to do is we need to be able to compete on a world scale with other jurisdictions that may look at carbon intensity differently than we do. We need infrastructure. We need the ability to sell our stuff to the highest bidder.
I think with this fourth Liberal government in a row, maybe now people are starting to, and with the way Donald Trump or the current administration is in the United States, maybe a lot of Canadians are starting to realize that putting 100% of our future in the hands of someone who may not really need us that much is maybe not our best idea. Maybe we need to broaden our horizons a little bit and sell our commodities or our resources across multiple jurisdictions. Who knows where this is going to wind up over the longer term. I would hope that Mr. Carney can realize that our responsible Canadian energy industry is part of the solution and not part of the problem at all. I think time will tell.
We'd just like to bring us to a close today, Alex. We've covered a lot of ground on Journey's asset base and your strategy. Can you just share your key thoughts on Journey's future growth profile, and is there anything in the market or we've overlooked?
Yeah. I think we've covered everything. To bring it to a close and just to kind of summarize, I'll go back to that chart on page 12 where I talk about this development plan. And I've talked about companies trading at three times operating income. If you can get your head around this CAD 47.50 netback over the next few years, and if you can get your head around kind of us driving this development wedge up to 6,000-8,000 BOEs a day by 2030, 2031, you look at that chart. One of the things, you look at that chart and you go, "Hey, there's been a lot of capital spent." The reality is there's also been a lot of cash flow through that period. By 2030, we've kind of taken more money out of the play than we put into it.
What I'll say is we've got 6,000-8,000 barrels a day. Let's just say 6,000 barrels a day at CAD 47.50 netback and three times operating income. That's over CAD 300 million of incremental enterprise value or CAD 4-CAD 5 a share that you're adding on that chart alone. Because this is kind of capital neutral and we've taken out as much as we've put in, that means that all of your existing cash flow between now and 2030 can go to maintain your production, pay your G&A, pay your interest, and kind of maintain your current enterprise of like CAD 180 million. I mean, when you work that all through, I mean, that's a tremendous value proposition for the company. You sit there going, "Okay, well, I can see all this".
I'm not quite sure. Within two to three months, you're going to read about the seven wells that we've drilled. Like I say, we've got three of them on now. The four of them will be on very soon. They're almost done being completed. You'll be able to see how those wells are doing. You'll be able to compare that to the type curve. It will become more and more apparent that the assumptions that we have on that slide and slide 12 are real. Once you see that, you can kind of do the analysis for yourself, right? The conclusion in our corporate presentation is that we're different from other microcaps. Yeah, we're undervalued as a company, but we think we know why. We think we're undervalued because we have a lot of net asset value, but not as much operating income.
We think we figured out with the Duvernay how to address this situation and address the undervaluation. We think that's going to lead to tremendous things for us. We've got very significant insider buying. Myself and our Chairman, Craig Hansen, we bought over 1.1 million shares since last fall, put more than CAD 1.5 million of our own money into the company. Both of us have been buying a lot. Also in the company, you've got this power business. You've got this Medicine Hat polymer flood that's going to give you free cash flow for years to come. Then the CAD 30 million that we spent on the Duvernay to this point, drilling and completing these wells, the production's not on yet. You're going to see it in the next few months.
All of this stuff is going to unfold in the next few months. Thanks for putting this together. I think that kind of wraps it up in that I see tremendous potential in the company. I'm putting my money where my mouth is. I'm extremely excited to report to all of you the results of these new wells over the upcoming months.
Alex, I think we'll leave it there for today. We look forward to hosting another fireside chat to get a progress update on the Duvernay. I'd like to thank the participants for joining us for today's fireside chat with Alex Verge, Journey's CEO. Our research on Journey Energy can be accessed from our website, www.watertowerresearch.com. The views expressed in this fireside chat may not necessarily reflect the views of Water Tower Research LLC and are provided for informational purposes only. This fireside chat may not be redistributed or reproduced without the written consent of Water Tower Research and should not be considered research nor a recommendation. WTR is an investor relations firm, not a licensed broker, broker-dealer, market maker, investment bank, underwriter, or investment advisor. Additional disclaimers can be found at our website, again, www.watertowerresearch.com. Thank you very much, Alex, for taking the time to join us today.
Thank you, Jeff. Thank you, Water Tower.