Good morning, everyone, and thank you for joining us today. On the call from Freehold are Rob King, our COO; Dave Hendry, our CFO; and Todd McBride, our Manager of IR.

Before we jump into our Q1 results, I just wanted to highlight some of the structural improvements that we have been working on at Freehold. First off, most of you would have seen our end of April news release highlighting that Freehold and Rife have mutually agreed to terminate the management agreement.

This management agreement has been in place since Freehold inception in 1996. And for a long time, it was mutually beneficial to all the companies involved.

Today, Freehold is a much larger company with a broader North American mandate. We no longer have working interest assets that benefited from Rife's expertise, and we've been very focused on building our royalty business through strategic acquisition work.

With all this as a backdrop, it created the right opportunity to refine our business structure and terminate the management agreement. So effective May 1, we have a fully dedicated team of executives and employees that are solely focused on Freehold.

So this change has really simplified our governance and streamlined our decision-making process as we look to keep building our business with the continued emphasis on generating value for our shareholders. The leadership and employee continuity will ensure a seamless and stable transition to this revised governance and operating model.

CNID, as our major shareholder, will retain a seat on the Board as they have been a valued investor and contributor to our Board since inception in 1996. I also want to touch on yesterday's announcement that we are in the process of putting an NCIB in place to provide flexibility in our return of capital structure through share buybacks.

We have the size and scale and have increased the stability of our cash flows to look at other ways outside of a dividend to drive shareholder returns. Our buyback strategy will develop over time, but our dividend policy remains unchanged with this announcement.

Dividends will continue to be the main method of returning capital to our shareholders. We are continuing to target a 60% payout ratio.

We will take a disciplined approach to share buybacks. Along with our share price, we will look at our expected cash flows and debt levels, as well as any potential acquisition opportunities, as key decision factors in determining when to buy back shares.

So if we turn to our Q1 results, our production was 16,248 BOE a day in the quarter. Taking our 2024 acquisitions into consideration, this is the highest level of production since Freehold started in late 1996.

65% of our production was liquids weighted, contributing to $16 million in funds from operations in the quarter or $0.42 a share. Our realized pricing averaged $49.25 BOE in Canada and $72.64 BOE in the U.S., a premium of 47% on U.S.

production compared to Canada. This was driven by higher oil weighting in the U.S., light oil pricing and lower transportation costs to benchmark pricing sales points.

We also had a robust leasing in Q1, with leasing of our U.S. mineral title lands setting a new high watermark at $3.3 million in the quarter.

Overall, we have 14 new leases in Canada and 11 in the U.S. And together, they contributed a healthy $3.9 million in revenue.

Drilling in Q1 was up 12% from Q4 2024 levels on both the gross and net basis. Most of the increase is attributed to the larger land base in the U.S.

as we did see some softening in wells drilled in Canada compared to Q1 2024. This was mainly due to a pullback in activity in the Viking compared to the prior year, but this was somewhat offset by the increase in activity in our oil-weighted plays, including Southeast Saskatchewan light oil and the Mannville Stack.

One of our biggest growth plays in Canada continues to be our heavy oil operating areas. So with that, our heavy oil production is up 19% from Q1 a year ago, with continued strong activity levels in the Clearwater and Mannville Stack.

Freehold's lands are well positioned throughout the basin to capture the momentum in the conventional heavy oil window, with multilateral drilling, favorable Crown-led royalty structures and narrower heavy oil differentials after the TMX pipeline start up last year. We also continue to see growth in our broader Deep Basin asset base.

This production is in the gassier area of our portfolio and we've seen steady production growth over the past three quarters. We have 25 million a day or 4,100 boe/d of Canadian gas exposure heading into what is anticipated to be a strengthening of AECO gas pricing with the completion of LNG Canada project online in Q3 of this year.

Next, I would like to just take some time to speak to activity in the U.S. There have been a lot of headlines over the past week or two on the Permian, with some viewing it as rolling over, while others are looking at rig counts and implying production is falling off.

I think there is a few things to keep in mind when we frame Freehold's opportunity set in the U.S. First off, to put things into perspective, if the Permian were a country, it would rank ahead of Canada in terms of both oil and gas production.

There is a tremendous amount of resource and opportunity here. The Permian produces over 6 million barrels a day of oil compared to the 5.8 million barrels a day that Canada produces.

In terms of natural gas, the Permian produces 26 Bcf a day, while Canada produces 18. So just putting this into context, compared to Canada, just helps show how big the Permian is relative to the supply of energy in North America and the opportunity that lies ahead.

Time and time again, it's shown that the best place to find oil is where you have already found oil. And we feel there is a significant runway that remains to be developed in the Permian.

And as technology continues to progress, there will be even more resources to recover in the years to come. We do share the view that the pace of production growth in the Permian will not likely continue at historical levels.

If we take a look at Canada, where conventional oil production has stayed relatively flat for the past 25-plus years, it is examples like the multilateral drilling technology being used in places like the Clearwater and Mannville Stack and in Southeast Saskatchewan, along with frac design, unlocking Montney and Duvernay resource, along with associated condensate growth that are really backfilling the decline and keeping overall conventional oil production relatively flat. We see a very similar situation in the U.S.

Most of the historical production in the Permian is coming from a handful of reservoir benches or zones that are present, and we are now seeing development in the rest of the benches contributing to production longevity in the Permian. As we think through rig counts, despite the pullback in active rigs, operators are able to do more with less.

Rigs in the Permian are becoming much more efficient in drilling as technology continues to progress. Rig counts certainly aren't at the record levels of 2018, but wells drilled remain very similar to 2018 levels.

If you look at the meterage drilled in the Permian, you'll find that the increase in rig efficiency is making up for the lower rig counts. I think what's very key and what we've really been focusing on very specifically and strategically is growing our portfolio in the Permian to maximize our footprint in the undeveloped benches and drilling spacing units to take advantage of production growth capacity on these targeted lands.

Our existing lands, complemented by our efforts in the ground game, form the basis for a rich inventory of light oil drilling locations. Our recent leasing activity focused on deeper benches in the Midland Basin highlights the opportunity set that exists.

So to wrap up today's call, I'd just like to address that market volatility that Trump and other factors have introduced over the past few months and how that impacts what we are expecting to see for the remainder of the year. We are maintaining our production guidance for 2025.

We are starting to see some operators tweak their 2025 capital plans, but there are still far too many unknowns to change their overall views today. The breakup season in Canada is upon us and we will be watching drilling activity coming out of breakup to give us a better sense of the balance of the year.

In the U.S., we have positioned ourselves in the lowest breakeven plays under investment-grade operators who take a long-term approach to capital planning. As a reminder, our largest corporate payer is ConocoPhillips at 17% of our revenue, and our second largest corporate payer is ExxonMobil at approximately 13% of our revenue.

These investment-grade operators have signaled they will continue execution of their strategic plans throughout the commodity price cycle. So overall, the quality of our payers, along with the plays we are positioned in and the overall financial health of our industry, gives us confidence that our payers will manage through the commodity price variability and deliver on their plans.

Our cash flows, we expect our larger and more balanced portfolio to support our ability to generate cash flows. The price we need to cover off all our costs plus our dividend is about $50 a barrel West Texas Intermediate.

We have a view that although oil may fluctuate down towards that level at times, it will not stay at that level for an extended period. And then what that means to you, as a shareholder, is that the dividend is sustainable.

So at Freehold, investors get a multi-decade inventory of drilling locations across an expansive Canadian and U.S. portfolios, $1.08 a share annual dividend, which is covered at oil prices in the range of US$50.

So with that, we are happy to take questions.

Yes. I think we'll just address the questions that are coming in on the web.

Sure. The first one is on NCIB.

Is this the first time that Freehold will have an NCIB? And how are you planning to use it to optimize shareholder returns?

Hi. It's Dave Hendry here.

Yes, this is the first time that Freehold has implemented an NCIB. And so just putting it in context, we're going through the process of implementing it.

It actually hasn't been approved and active at this point in time. So that's step one.

And so with an NCIB in place, that gives us more optionality to realize shareholder value. So don't expect us to immediately start executing on an NCIB, but it is an option that we are going to use tactically when it makes sense.

And so ultimately, it's just another option in the toolkit to make sure that we're doing the right thing for shareholders.

Thanks. The next question is on lease bonuses.

Are these results repeatable in the U.S.? And how should we think about these going forward?

So in the quarter, we had – Dave mentioned, we had 11 leases signed on our U.S. assets.

Most of that was in the Permian. We did have one in the Haynesville.

And the bulk of the $3.3 million in revenue was from a private E&P that's focusing on the Barnett formation. And that sort of really dovetails back to our Investor Day, where we sort of walked through the emerging and the – first generation, second generation and emerging benches, and those emerging benches, being those deeper Barnett formation.

There, we've only seen about 400 horizontal wells drilled compared to the 25,000 horizontal wells drilled in the other eight benches in the Midland. I think one of the important stats to remember is 80% of the 1.2 million acres of land that we have in the U.S.

is mineral title. So there is a lot more opportunity set that we anticipate going ahead of us.

We already have about $1 million of lease bonus in the U.S. for the second quarter.

How repeatable is three? Again, we'll sort of see.

I think we do expect it to be more episodic, but the point is there is a lot of mineral title that we have in the Barnett formation, where a lot of these leases are being signed, is proving to be more prolific and in more areas than we had anticipated.

Great. The next question is on cost structure.

How should we think about the cost structure in terms of the management agreement being terminated with Rife?

I can take that, Dave Spyker here. Really, when we look at that, the cost impact is not material at all.

The employees' time is allocated based on the efforts that they're putting into Freehold historically. So it's been – that cost structure aligns with where the work effort is going already.

So maybe just a bit of one-time cost, and again, had a minor costs just associated with separating our infrastructure, but one-time minor impact. And so what we're getting for very similar cost structure and no longer paying CNID and management fee going forward is that we get a dedicated staff to work on Freehold, which I think is a huge step forward.

Great. And I would actually like to turn it back to the operator.

I believe we have someone on the telephone who'd like to ask a question.

Yes. Good morning, guys.

More just clarification. David, I think you mentioned a change or recalibrating activity levels through the second half.

Was that just a broader comment because pricing has softened? Or have some of the operators given you indications that they're looking to alter capital and activity through that second half?

Yes, I think just a broader comment, Travis. I mean what we're seeing today is that we're seeing really strong licensing in Montney and Deep Basin that we have not had licensing at that level historically.

So those are high impact volume wells. And broader, we're not seeing our operators changing their guidance right now.

And so I think that while just waiting to see what happens through breakup, we'll get a better sense of what's happening in Canada. As typical this time a year, we see licensing slowdown, and that ramps up into the latter part of the quarter and then starts to translate into drilling in June.

So again, we think that in Canada, we like some of the licensing that we're seeing on the gassier plays and licensing on the oil plays where we've seen a lot of our activity. We're starting to see that in Saskatchewan, now Southeast Saskatchewan.

And as operators firm up their plans, we expect to see that in other areas as well.

And maybe just to comment, Travis, just on our U.S. portfolio, kind of important to remember who our top two payers are, being Conoco and Exxon.

Between the two of them, that's almost a third of our corporate revenue. Conoco made a comment on its Q1 conference call that their projects that they run are down to a $40 WTI price with a 10% return.

So we're obviously well in excess of those commodity price levels right now. And Exxon, in its Q1 conference call, kind of reiterated its growth plans that it's had, with the Permian being a key tenant of those growth plans.

Okay. That's perfect color.

Thanks, guys. That's all.

Sure. We have a few more questions from the webcast we would like to address.

In the Permian drilling, how should we think about the horizon being drilled going forward?

Yes. I mean I kind of touched a little bit on that on the leasing side.

I would sort of say it's still the middle, call it, eight benches make up the bulk of the drilling still on our Midland assets, but we are seeing increased drilling in that Barnett formation, the deeper formation, that a lot of our drilling success has come from. But as I mentioned, 5,000 wells have been drilled into those second generation benches, Middle Spraberry, Jo Mill, Dean, Wolfcamp C/D, and about 20,000 wells have been drilled into those Lower Spraberry, Wolfcamp A and B.

So between those, those eight benches make up the bulk of our Permian drilling.

Yes. And maybe just to add to that, when we talk about very targeted, specific acquisition strategy in the Permian.

In the Midland Basin itself, we've assembled our land base. A third of it has not had horizontal drilling on it yet.

And so when Rob talks about these first-generation benches being the Wolfcamp A and B, Lower Spraberry, which were the initial targets of horizontal drilling, and then expanding out to the other five kind of, what we're calling, second-generation benches; and then these emerging benches, where we're being intentional in acquiring land that haven't even has the primary benches drilled yet. And so that's why we're really confident in the portfolio that we've assembled.

And it's not coincidence that our top operators in Midland, being Exxon, is also targeting those areas as they see the same opportunity set that exists.

Thanks. And the last question is how much exposure does Freehold have to the multilateral drilling going on in the Western Canada sedimentary basin?

Yes. With respect to that, we've had good exposure on the heavy oil, both in the Clearwater and the Mannville Stack in the greater Lloydminster area.

And we've also got our biggest area of feed title, about 0.5 million acres is in Southeast Saskatchewan, which is just really starting to catch the multilat drilling bug. If you recall, in April of last year, the Saskatchewan government introduced a royalty incentive for this multilateral drilling.

And the incentive was announced in April. And during breakup, started to see operators license those wells in the latter part of the year and with excellent well results.

And so when we think ahead with our acreage position there and with the opportunity set that exists in multi-horizons for that light oil in Southeast Saskatchewan, we see that as a definite growth area for us.

Just one other comment on that. In last year, in 2024, we had probably close to almost 40% of the wells drilled on our lands were multilaterals.

That's almost a doubling from what we observed in 2021, 2022, 2023. So it really is expanding across our land base.

Thanks. That's all the questions from the webcast.

Well, thanks, everyone, for joining today. Appreciate your participation in the call today and for your interest in Freehold.

Thank you.