Thanks, Sylvie, and good morning, everyone, and thank you for joining us here today. There are five members of our management team here with me at this time: our Senior Vice President and CFO, Thanh Kang; our Senior Vice President, Production and Operations, Joel Armstrong; our Senior Vice President, Asset Development and Information Technology, Dave Mombourquette; and our Vice President, Unconventional Division, Joey Wong; as well as our Vice President, Conventional Division, Chris Bullin.

Before we get started today, I would like to remind everybody that all statements made by the company during this call are subject to the same forward-looking disclaimer and advisory that was set forth in our news release issued yesterday afternoon. We are once again pleased to report exceptionally strong operational and financial results for the first quarter of 2026.

We are very proud to report that our technical and operations teams continue to deliver execution through an active first quarter capital program, with asset productivity continuing to exceed expectations. Average production for the first quarter was 391,416 boe per day, comprised of 242,000 boe 242,107 barrels of liquids per day and 890 million cubic feet a day of natural gas, exceeding our budget expectations by approximately 19,000 boe per day.

Through top-tier execution and strong asset-level performance, this production level significantly outperformed our budget expectations for the first quarter. Expecting this performance to continue prompted us to raise our 2026 production guidance by 7,500 boe per day, or 2%, to 380,000 boe per day.

As well, at current elevated light oil and condensate prices, this higher production is generating materially higher cash flow. Combined with maintaining our $2 to $2.1 billion capital program, this is driving increased funds flow and profitability relative to our original plan.

Our first quarter funds flow of over a billion dollars, or 85 four 84 cents per share, increasing 12% per share compared to the first quarter of 2025. After capital investments of $626 million, we generated $340 million of free funds flow.

This allowed us to reduce net debt to $3.2 billion while returning $221 million to shareholders through our base dividend. Consistent with our long-term counter-cyclical capital allocation strategy, we will prioritize debt reduction with excess cash flow at current commodity prices.

This strengthens our financial flexibility to redeploy capital towards share purchases, accelerate growth, or tuck-in consolidation opportunities in the future. The progress we have made since closing the Veren acquisition one year ago has been remarkable.

Improvements within our control, including execution, well design, development planning, and production practices, supported by rigorous technical analysis and cost discipline, have delivered the results we are experiencing today. Whitecap is positioned to capitalize on commodity price cycles inherent to our industry, and the current environment is no exception.

Our operational execution allowed us to capture additional benefit of higher prices in March and April to date, as we have completed the first quarter capital program with all the planned light oil and condensate wells brought on production on or ahead of schedule prior to spring breakup. We were running 18 drilling rigs during much of the first quarter, and now will continue to run six rigs through breakup on our unconventional and Glauconite assets, and will be ready to hit the ground running on our light oil conventional assets in Alberta and Saskatchewan once breakup subsides later in the second quarter.

We are maintaining our 2026 capital budget. Any potential future adjustments will support increased production growth in 2027 within our 3% to 5% target, should higher crude oil and condensate prices persist at this time.

I will now pass it on to Thanh to further discuss our financial results. Thanh?

Thanks, Grant. Our first quarter funds flow of $1 billion was driven by strong operations, continued cost discipline, and our ability to capture elevated light oil and condensate prices during March.

For the quarter, our funds flow netback increased to $29.12 per boe, up 5% year-over-year, despite Canadian dollar WTI crude oil prices down approximately $4 per barrel and AECO natural gas prices down approximately 7% as compared to the first quarter of 2025. This improvement was driven by stronger price realizations across crude oil, condensate, and natural gas, along with a meaningful reduction in our operating costs.

Realized pricing for crude oil and condensate benefited from a higher proportion of condensate in our production stream, which typically trades at a premium in Western Canada due to strong oil sands demand for diluent. Our core growth areas are focused on light oil and condensate-rich assets, which we expect will continue to support strong price realizations.

Our natural gas production benefited from price diversification, with realized pricing of $3.18 per Mcf, approximately 60% higher than the average AECO price. While diversification carries higher transportation costs, the incremental revenue more than offset these costs during the quarter.

Our long-term target remains to diversify 50% of our natural gas volumes away from AECO. We have made significant progress reducing operating costs, and we continued this trend in the first quarter.

Our $12.02 per boe operating expense was down 11% year-over-year, reflecting ongoing efficiency gains across our operations. As a result, we are improving our full year 2026 operating cost guidance to $12 to $12.50 per boe.

The sharp increase in strip crude oil prices through to the end of 2027 had a timing impact on our net income for the first quarter. We recognized an unrealized loss on commodity contracts of approximately $500 million, or 40 cents per share, against our net income.

The benefit of higher commodity prices will be realized over the coming months and years. During March, we also prudently added to our crude oil hedge positions, locking in attractive prices for 2026 and 2027.

For the remainder of 2026, we have approximately 35% of our net crude oil production hedged at an average swap price of approximately $95 Canadian per barrel. For 2027, we have 23% of our net crude oil production hedged at an average swap price of over $91 Canadian per barrel.

Our natural gas hedge positions are largely unchanged, with strong prices locked in for the remainder of 2026, with 28% of production hedged at an average swap price of over $4 per GJ, and in 2027, 13% of production hedged at an average price of approximately $3 per GJ. Bringing this together, and incorporating our increased production and strong crude oil and condensate pricing, we forecast $4.3 billion of funds flow for 2026 at current strip prices.

This translates to $2.2 billion of free funds flow. Our balance sheet is very strong, and as Grant noted, we will prioritize debt reduction with excess funds flow at current commodity prices.

Our current net debt of $3.2 billion represents a net debt to annualized first quarter funds flow of only 0.8 times. At current strip prices, our year-end net debt would be reduced to $2.2 billion, which equates to a net debt to funds flow ratio of only 0.5 times.

Finally, during the first quarter, we proactively reduced our credit facility by $500 million, lowering standby fees and extending the maturity to September 2030. I will now pass it off to Joey for more remarks on our unconventional results.

Thanks, Thanh. Our Unconventional Division delivered another strong quarter, with production averaging just under 200 240,000 boes per day, approximately 4% above our budgeted expectations.

Consistent with prior quarters, this outperformance comes largely as a result of strong new well results and continued improvements in execution. Aggregate well performance exceeded expectations by 10%, while drilling and completion activity came in approximately two days per well faster than planned.

This cycle time compression has been a consistent trend for the division over the past several quarters, stemming from improvements to our drilling and completions key performance indicators. Those indicators, as measured in meters per day of drilling or tons per day of completions operations, has seen improvements of 27% and 12%, respectively, as compared to historical levels.

Importantly, these aren't just pace setters, but they are average gains and are being realized across multiple assets and programs. This speaks to the consistency of execution improvements being realized across the portfolio.

These improvements are being driven by a combination of well design optimization, continued advancements in completions execution, including the application of actively guided frac operations, and the use of data-driven execution workflows across our asset base. We are leveraging a deep, proprietary internal data set over 1,100 Montney and Duvernay wells, rich with producing and execution data.

What we're now seeing is the benefit of scaling learnings and applying them consistently across our expansive portfolio of Montney and Duvernay development opportunities. These efficiency gains are now incorporated into our updated guidance.

We have adjusted our activity levels to reflect these improved cycle times, reducing our unconventional rig count to six from seven, while maintaining our capital program. This effectively smooths capital through the balance of the year, improves rig utilization, and enhances overall capital efficiency without increasing spend.

Turning to Kaybob, we are pleased to report that our two planned plug-and-perf pilots in the first half of the year have been executed successfully. From an execution standpoint, results have been very encouraging.

Effectively stimulated stages, which is one of our key measures on execution, exceeded 95% across all seven wells, and overall cost came modestly below budgeted expectations. This translated into an approximate $2 million per well cost advantage relative to single-point entry completions in the area.

The two pads are now in their early-time cleanup production phase, and our technical teams are gathering important flowing and diagnostic data. Further success on these subsequent levels of evaluation will define the overall success of the pilots.

The level of cost improvements has the potential to drive approximately 20% uplift in well-level economics, which represents a meaningful opportunity to add incremental value to this land base. We have a third pilot pad planned for the second half of 2026 for the Gold Creek area, which is to the north of these two initial pads.

We will incorporate learnings from this pilot program to inform future development decisions as we continue to pursue meaningful, value-adding optimization initiatives on these lands, while controlling the pace to ensure we are not exposed to material corporate-level risk. It is important to note that with improvements in our overall completion execution and reduction in cycle times, the cost difference between single-point entry and plug-and-perf has narrowed significantly in some areas of our land base.

The important part is, ultimately, we feel comfortable deploying either completion technique, and we'll let our technical and economic analyses determine the optimal technique on a pad-by-pad basis. At Lator, our facility build continues to progress very well and now stands at approximately 70% complete, with both cost and schedule remaining aligned with our accelerated on-production timing for the fourth quarter of this year.

Overall field construction is well advanced, with the majority of major equipment now delivered to site, which materially de-risks the remaining construction timeline and subsequent ramp-up. That ramp to nameplate capacity of 35,000 to 40,000 boe per day of throughput is expected over a period of 12 to 18 months from the in-service date of the facility.

In parallel, we continue to gather subsurface and production data from both legacy and new wells in the area. As we continue to refine our understanding of the asset through execution, we will further assess and incorporate available upside and will adjust our expectations and development plans accordingly.

In Kaybob, wine-rack development is now fully underway across our high-confidence lands, which represent approximately half of our undeveloped acreage in the area. Based on results from this configuration, which was first piloted with wells spud two years ago, we are seeing consistent improvements of 10% to 20% in both initial production rates and expected ultimate recovery.

We are very pleased with the incremental value that has been added to these lands through the application of rigorous, measured, and thoughtful optimization. Building on that foundation and leveraging a wealth of information from the nearly 50 wells drilled in this configuration, we are now progressing to the next stage of optimization within a subset of these lands.

This involves targeted downspacing pilots on two pads in the southern portion of the Kaybob asset base. This area has demonstrated low inter-well communication when developed with this wine-rack configuration, and as a result, has provided the opportunity to improve the area-based recovery of these lands through this downspacing from an average of five wells per section, or 330 m inter-well, down to six wells per section, or 275 m inter-well.

When combined with the gains realized from wine-racking, we estimate a benefit of 20% to 25% to asset values of affected lands through the addition of an additional 20 to 25 incremental inventory locations. Lastly, at Resthaven, we will be commencing our first delineation campaign of these prolific lands, with a two-well pad to be spud in the coming months and brought on production near year-end.

While the asset is more gas-weighted than the balance of our current development focus, wells in this area can still be expected to produce an impressive amount of liquids, and this two-well pad will begin to assess that, along with validation of our models for the estimates of modern-day optimized development on these lands. This work is an important component of our broader technical readiness strategy, ensuring that we continue to advance our understanding of key assets and position them for development at the appropriate time.

With that, I will now turn it over to Chris to discuss our conventional assets.

Thanks, Joey. Our Conventional Division hit the ground running in the first quarter of 2026, with momentum carrying forward from 2025, as we delivered strong production performance of over 150,000 boe per day of light oil-focused volumes.

Outperformance of 6% relative to budget expectations was achieved by stronger than expected growth volumes and timing improvements, supported by a very active nine-rig Q1 program, along with solid baseline performance as our teams continued to enhance efficiencies through optimization initiatives and improved operating conditions. Our high-confidence and high-margin conventional assets continue to underpin Whitecap's sustainability.

With an 80% liquids weighting, the majority of it being light oil, a sub-20% decline, 52,000 barrels per day of dedicated EOR production, and extensive infrastructure already in place, we were well positioned to capture meaningful upside as oil prices strengthened materially late in the first quarter. This diversified portfolio continues to provide Whitecap with a significant competitive advantage, allowing us to maintain budget flexibility to allocate capital across multiple high-quality, quick-cycle opportunities that could rapidly add light oil production.

Saskatchewan was our most active conventional area in the first quarter, with 45 wells drilled utilizing up to six rigs, primarily targeting the Frobisher, Bakken, and Viking. Q1 outperformance was driven by continued enhancements to our growth programs, with improved cycle times, more focused development sequencing, alongside strong base production supported by lower than anticipated downtime, optimized waterflood performance, and increased service rig utilization—an exceptional start to the year.

Our Frobisher program saw 19 wells drilled with three rigs, which represented the most active Q1 on these assets to date. Our teams saw operational improvements on drilling costs, with a 7% reduction in a dollar-per-meter metric and a 15% reduction in equipping costs relative to historical performance.

In the Bakken, our open-hole multi-lateral development continues to push technical and operational boundaries, highlighted by the recent drilling of a 10-leg open-hole multi-lateral well with lateral lengths up to 3 miles. With over 43,000 total meters drilled, this represents the longest well drilled in Canada and underscores the strength of our technical and operational capabilities.

The well was recently brought on production in April, and positive results are expected to enhance our inventory depth, improve long-term capital efficiency, and further validate the applicability of open-hole multi-lateral technology across our conventional asset base. These inventory enhancement initiatives are characterized as optimizing lateral lengths and reservoir contact to maximize per-well economic metrics, our primary objective.

Shifting to Alberta conventional assets, which delivered the majority of our outperformance of approximately 5,500 boe per day. Base optimization initiatives, combined with access to previously unavailable third-party infrastructure capacity in the Glauconite, contributed to approximately 3,000 boe per day of upside in the Glauconite volumes during the quarter.

The balance of outperformance comes from new well growth and volumes from our Glauconite, Cardium, and Charlie Lake assets—all areas that have shown year-over-year enhancements, such as an increased lateral length and optimized completions designs. With that, I'll turn it back over to Grant for his closing remarks.

Thanks very much, Thanh, Joey, Chris, for your comments. I want to reiterate how remarkable these results are, especially when coming less than one year after combining the two sizable companies and asset bases.

The integration has been both rapid and successful, and our team is already delivering meaningful gains in productivity and free funds flow, as we've discussed. Our performance is underpinned by a few key attributes that define our strategy and differentiate Whitecap.

Number one: operational execution. Our operating capabilities continue to improve, driving shorter cycle times, greater efficiencies, lower costs, and strong production results.

Number two: asset quality, duration, and optionality. We have approximately 10,500 drilling locations across light oil, condensate-rich, liquids-rich, and natural gas assets, providing decades of inventory.

The quality of the inventory, combined with our track record of execution, continues to drive consistent outperformance. Number three: high netback.

Our predominantly light oil and condensate production generates strong funds flow netbacks, further supported by cost discipline. Our focus on controllable costs continues to drive margin expansion.

Number four: decline rate. Our current decline rate of 29% lowers the capital required to sustain production and supports higher free funds flow.

Number five: balance sheet strength. Maintaining a strong balance sheet provides the flexibility to execute our capital allocation strategy, including returning capital through our base dividend, pursuing share repurchases, accelerating growth when returns are strong, and evaluating accretive acquisition opportunities.

Number six, probably most important: Whitecap personnel. Across our office and field personnel, we enjoy the exceptional results because of the commitment and dedication of our talented team.

Together, with these attributes differentiate Whitecap and enable the results we delivered in the first quarter. We will remain focused on driving further profitability and delivering superior long-term shareholder returns.

With that, I'll now turn the call over to the operator, Sylvie, for any questions. Thank you.

Hi, good morning. Thanks for taking my questions, and congrats on a incredibly strong quarter.

My first question is probably directed a little bit at Joey. You've commented in the past, as well as in your prepared remarks today, around kind of your view that effective stimulation along the length of the wellbore is a really strong indicator for, A, a successful completion, but B, also the possibility of kind of improved productivity.

As you evaluate these plug-and-perf wells at Kaybob, can you talk to us about a little bit of the, we'll call it the metrics or the information that you're trying to gather that kind of prove out the success in terms of what you're trying to achieve here with plug-and-perf? Then secondarily, can you highlight maybe what kind of rock characteristics or targets create kind of a viable opportunity to deploy plug-and-perf versus single-point entry as you kind of take this pilot project and roll and potentially experiment around other areas of the field?

Hey, Dennis, thanks for that. Appreciate you highlighting there that's exactly how we view the evaluation process there is like you said there, we noted that execution went well, very pleased, of course, and reiterating there, able to even optimize along the way with the actively guided frac operations that we do have.

As we noted there, yeah, that's good, and we're happy with it, and the greater than 95% completion effectiveness is now logged for these wells, and we're there. The second phase, as you're asking about here, is the information gathering phase on the early production.

What we're looking at here is a wide suite of diagnostics that we look at. Important to note, actually, as well, Dennis, that the diagnostics that we do, it's not unique to this pilot, but part of our normal course of operations when we're looking at assessing the effectiveness of the development of these lands.

To give kind of a view into what we're looking for, and against it's done through a wide variety of diagnostics, but ultimately what we're looking for is the geometry of the fracs, and if it conformed to our expectations, so that'd be the first one. The second would be to see how the rock has responded to that treatment, how much rock we've contacted.

We're also looking to see where the contribution for production is coming from along the lateral to make sure that it's uniform there. Then, also importantly as well, we're looking at how the wells are interacting with each other on the pad and with respect to wells that exist in the area.

We're taking a look at all of the producing and interpreted information that comes from all of those to come up with a full picture to understand, okay, yes, the execution went well, but is the development actually getting to the ultimate end that we're looking for, which is an optimized result on an economic basis? It brings me to, I guess, your second question there of what rock characteristics are good for plug-and-perf?

At a high level, you're going to be looking for rock that's relatively homogenous, that you have a history of a design and associated execution on that you can build again that confidence around the interpretation on the two phases that I talked about there, both execution and the subsequent on production. Generally speaking, the Montney and Duvernay have those characteristics, and that's why 90% to 95% of the asset bases that you see in the Montney and Duvernay and similar ones in the Lower 48, for example, are done with this plug-and-perf technology.

There will be pockets within there that you see slight differences in the rock, or different hazards or risks that you want to control around that you might then revert to a different technology or a different development design. Again, I know we've talked about this before, but it's worth reiterating right now that the completions technology is one of many design inputs that we have.

We adjust things like our tonnage intensity, the nature of our proppant and slurry, where we land the wells. All of those things go into that in order to, again, drive the most effective development that we can on the asset base.

Kind of went around on a bunch of different topics there, Dennis, on your question there, but did that cover it, mostly?

No, yeah, I really appreciate that context there. You definitely answered the question.

My second question here is kind of shifting towards the conventional side. You've obviously showcased really a lot of kind of innovation, especially with a 10-leg multi-lateral at a 3-mile length.

This really kind of builds off of what you highlighted at the Investor Day. I was actually hoping to find out, A, how do you think about frankly, inventory replacement within the conventional side, just as you're able to convert, we'll call it, additional inventory into premium inventory?

Then how do you also balance targeting, we'll call it, higher-quality reservoir in terms of these opportunities versus ones and testing opportunities that maybe deemed kind of lower-quality reservoir and seeing kind of what the delta is in terms of well performance? Thanks.

Hey, Dennis, thanks for that question there. As far as inventory goes, we're always trying to to maximize, I'd say, the capital that we're trying to deploy here and and enhance our learnings.

I think our teams have done a really good job of that time and time again, being very focused on on how do we reduce our overall, capital perspective, our capital deployment, I should say. Examples of that would be, as assets transition from from 1 mile to 2 mile to 3-mile development, you you really start to see those capital efficiencies continue to improve.

I think our teams have done a a great job showcasing that. With respect to, how we're upgrading that inventory, our our teams are always very pragmatic in in understanding how we, continue to push forward and and and allocate, I'll call, dollars to more strategic initiatives or initiatives that would be, not our our premium-style inventory, we continue to enhance that, that that inventory for from a Tier 1 perspective.

I guess where I'm going with that is we always think about, de-risking our lands in in a very pragmatic way, and we do allocate a small percentage of dollars to that every year. Again, one of the benefits of our portfolio having such a strong Tier 1 inventory position is we don't really need to take those unnecessary risks, we will allocate small percentages of strategic dollars to helping to validate and enhance that.

From from a targeting quality perspective, I think the Bakken's open-hole multi-lateral be a really good example of that. Where we can take open-hole multi-lateral technology and help us to upgrade potentially lower reservoir that we wouldn't be targeting with standalone drills, I I think lengthening and and enhancing lateral lengths towards capturing more reservoir in the most efficient way possible is really, the key focus and and target for our teams.

I think again the Bakken's a really good example of that. We're always cognizant of that inventory that's, somewhat, requires some more delineation and some more risk, and I think that, continuing to enhance lateral length is probably a key for that for us.

Again, I'll just reiterate that we don't need to take any unnecessary risk because we benefit from having such a strong inventory portfolio on the conventional side that we really are in an enviable position to be very tactful in in how we deploy those those opportunities.

Great. Thanks for the context there, Chris.

I'll turn it back. Thank you.

Sure. Good morning.

A couple quick ones. I guess first on the capital costs.

Are you seeing any signs of higher capital costs in your business, and if so, kind of what service lines would those apply to, or if not, kind of what do you expect to see over the next year or so? Just to help folks frame that out.

Then second, I saw the comments in the release, but is there a commodity price environment that would cause you to increase your capital program this year and next? My sense is probably not for now, but any color on what could change and kind of what might drive that would be appreciated.

Thanks.

Hey, Michael. Joey here.

On the service cost side, the short answer is nothing material as of yet. We'll probably expect to see some pressure on things that are more fuel-intensive.

Of course, diesel is a pretty acute thing that everyone's going to be feeling. To the extent that we've been able to, we've locked down a number of our services with contracts that largely shelter us from that.

On the diesel side, probably worth noting as well, when you look at the amount of fuel that we use in our drilling and completion operations, like the direct diesel that we'd be using on both drilling rigs and the frac spreads, prior to this, we had already displaced somewhere between two-thirds and three-quarters of that use on the unconventional side, at least, from diesel and towards our own sourced natural gas that's sourced from our own operations. We're naturally already protected against that as well.

Where we expect to see it, like I said, should be marginal, and the setup for us, at least, is good so far to be able to navigate through this. On the capital side there, maybe look to Grant to answer that one.

You asked about increasing capital program. Our objective here, as we talked through the presentation, is we do think counter-cyclical.

In the higher pricing environment, it's not as to increase our capital program, especially with the type of results that Joey, Chris, and the operating team are bringing forward. Use that as a time to strengthen your balance sheet for future opportunities.

If there was any increase that we'd be considering, it'd be in the fourth quarter that would have an impact on 2027. In the meantime, we'll enjoy the benefits of the higher prices specifically on crude and condensate prices at this particular time, and use that to drive a much stronger balance sheet as we advance forward.

We've not had problems with the balance sheet, but our long-term strategy has been, in a higher pricing environment, delever as quickly as you possibly can and prepare yourself for future opportunities in how you want to deploy that capital. You wouldn't expect to see us increasing capital.

We will review our fourth quarter as we go through the balance of the year. At this particular time, there'd be no increase from the $2 to $2.1 billion.

Appreciate it. Thanks, guys.

Hey, guys. Good morning.

Just curious, the updated raised guidance, does that contemplate any steeper than usual dip in production in 2Q on breakup? Just wondering, we should assume that 4Q production should be at least as high as 1Q, but just any color you can give on the cadence of production over the next three quarters would be helpful.

Thanks for that question here. It's Thanh here.

As we would have talked about before, actually, in the third quarter, we've accounted for some turnaround activity at PGI Patterson, as well as in our Glauc in Central Alberta there. That'll impact our production somewhere in that 12,000 to 15,000 boe per day in the third quarter.

What you'll see is the outperformance, that 19,000 boe per day that we saw in the first quarter, a component of that is going to be performance-related, and a component of that is going to be timing, right? What Joey talked about in terms of the compressed cycle times, so as you can appreciate, some of that production is being moved forward.

That actually makes it harder for us to achieve our fourth quarter number. I think we're still very comfortable uplifting full year in that range of 7,500 boe per day.

More importantly, as you think about Q4, it's still going to be in excess of that 380,000 boe per day is what our expectations are.

Got it. Something that I think that we're noticing is the premiums that light oil and condensate are getting to WTI, and you guys call it out explicitly in your release.

Curious what you attribute that to? I'd imagine it's probably some dynamics that are further downstream in the US.

I guess more importantly, how long do you guys expect that to sustain?

It's Thanh here again. I'd say that, obviously, with the current Middle East conflict, there's lots of dislocations that are currently happening.

I think the primary contributors would be, on the certainly on the light side there, inventories are still relatively low, and there's strong export demand for light oil. On the diluent side there, the domestic demand was growth in the oil sands.

I think that remains strong. If you look at pricing for the month of May, it was positive $9 and positive $8 for lights and condensates, respectively, there.

As we think about the second quarter, we're still seeing pretty strong, as you look at the strip pricing there, it's trading somewhere in that $3.76 at the premium for the second quarter on MSW, and on condensate, it's about $2.60. Our forecast is a little bit more conservative.

I'd say that we're running still at a discount of $2.50 on the lights, and minus $1.50 on the condensate there. I think Q2 still going to be a very, very strong quarter for Whitecap here, considering we're producing 138,000 barrels a day of light oil and 55,000 barrels a day of condensate.

I think if the conflict continues to persist here, I think you could see this dislocation continuing, but we're certainly not embedding that in our guidance at this time.

Good stuff. Thank you.

Hi, thanks. Maybe, Thanh, just going back to your guidance question there.

I'm just thinking about these plug-and-perf designs and just the improvement that you're seeing. How much have you embedded these success with the results into your guidance, and is there more to come here as you basically replicate this plug-and-perf throughout other areas here going forward?

Maybe if there's any additional details in terms of how rapidly you want to deploy this new design here throughout the field?

Hey, Jeremy. I'll take this one, Joey.

Your question of what's been incorporated in the rest of the year, as it stands right now, the early-time flowback is within our expectations, there really isn't a change to what these pads are going to do. We have recognized that the cost advantage there, the $2 million per well that we spoke to, which, again, we're quite pleased about.

As it stands right now, everything is on track. With that, now with respect to your other question there of how quickly we'd look to roll that out, and how applicable this is to all the other lands, of course, and trying to get read-through to further capital efficiency gains is of course what I'm sure everyone's thinking about, including us.

It was probably worth taking a step back and looking at this. We observed that there is an ability to improve both design and execution on the plug-and-perf deployment, particularly on these lands, throughout the asset base, but again, particularly more acute on these lands.

The goal has been all along repeatable and optimized frac geometry, and doing that at the lowest risk-adjusted cost that we can at its most fundamental. Of course, if done correctly, if done appropriately with the right design and the right execution, the two results should be effectively the same.

It's not like plug-and-perf is getting us a better well. We're just getting the same, again, optimized frac geometry that we've designed around throughout the other dozens of inputs that I spoke to in the response to Dennis's questions there.

In terms of then assessing how quickly we want to roll this out, we'll be looking back at these pilots and looking to those diagnostics that we've outlined there to say, okay, based on what we're seeing here, do we see a reduction of risk on associated lands that we want to try this on? Can we advance the next stage of pilots with a certain level of confidence?

Do we need to go to another area in order to validate something that's a little bit gray on some of those dozens of technical indicators we're looking at? It's going to be multifaceted as we look at it.

Again, to reiterate, and again I'd mention this to Dennis as well, this is a risk-adjusted economic decision that we're trying to put into place to improve the capital efficiencies of these lands. It's no different than some of the other things that we've looked at that have moved the needle already to date.

We talk a lot about, again, where we're landing wells in the Duvernay, well design changes, whether that's larger casing size or how we're actually landing the wells. All of those different things leading to ultimately those improved KPIs that I spoke to there on the actual execution there, which has driven the improvement to capital efficiency, which we have highlighted in our corporate deck now, which have improved by 12% as compared to historical levels there.

Again, what we're going to do, and it's worth reiterating one more time, we're going to look at the data, and then understand what the best way is to go from there. If in portions of the land base there, and as mentioned in the prepared remarks there, if in portions of the land base we see improvement to single-point entry and that cost advantage isn't quite as wide, we're more than happy to stick with that technology in portions there as well.

To be determined there, Jeremy.

Okay. Maybe just an unrelated question here.

I keep looking at your 40-plus years worth of inventory. You talk about your premium inventory versus just regular inventory, I guess is maybe the way to say it.

Is there plans to potentially dispose of some of the non-premium inventory here, just given where valuations have moved for a lot of the logical buyers that could buy this?

No, at this particular time, Jeremy. The way we think about it, we've got premium inventory, and then it's not as though the non-premium inventory, if you want to use that terminology, isn't economic.

What we want to do is continue to mature what we'll call our lower-tier inventory into something we may spend capital on. We're not looking for third-party capital at this particular time.

There would be no particular reason for us. With advancing technologies and the pace is being undertaken, we don't feel there's any need to dispose of or utilize up the inventory set that we do have both in the conventional and the unconventional portion of our business.

If it gets to be that we're not deploying capital over a five-year period of time on these assets and we're definitive about that, sure, we'll look to maybe bring in third-party capital or dispose of those assets. Certainly not in a hurry.

At this particular time, when Canadian oil is trading at $142 a barrel, I can tell you we're hanging on.

Perfect. Thanks, Grant.

Good morning, guys. I guess my question is in the line of what Jeremy was getting at and maybe a bit more broader, but with the big Q1 beat, you've kind of planned pretty impressive productivity changes, faster cycle times, but as you look across that performance through Q1 and think about the rest of the year, how much of that outperformance would be related to more structural changes that you guys have implemented versus maybe some timing nuances from on-stream a little earlier than expected?

Then how do we think about that through the rest of the year as you capture structural changes, but then also the nuances of timing?

Perfect, Travis. I'll start this one, and maybe Chris can hop in on the conventional side there.

Actually where I'll start is actually the last point you made there in terms of timing and leaning back to what Thanh said there. Timing is a big component of what we're seeing in Q1.

When you look on the unconventional side, the beat that we had there as compared to our internal expectations, about two-thirds of the beat was on performance, so that was exceeding our expected productivity on the wells by an aggregate 10%, like we had highlighted. The other one-third is those cycle times.

Gives you a sense of where we notionally see things. Now what's built in for remaining outperformance on these wells, where we've seen direct relationship between cause and effect—how we're landing wells, how we're fracturing them—we do build those in live into our expectations, and that'd be incorporated into not just 2026, but as we build out our inventory and evaluate the whole asset base that we look at.

Where we're not seeing something that we can draw a clear causal relationship, we'll stick to the way that we generate the type curves in the first place, which is to look at area averages and lean towards that and continue to stay with that. It's a mix of both that we're seeing there, Travis, but again, partially recognized.

Maybe Chris on the conventional side?

Thanks, Travis. On the conventional side, very similar theme.

Everything we build is around risk forecast and normalized operating parameters. We think about the conventional side, about 50% is growth and 50% is base from an outperformance perspective.

A large chunk of that really was the Glauc optionality from an egress perspective. That really is one of the benefits of having such an expansive, interconnected systems that we can optimize very quickly.

When that capacity did become available for us, we very quickly acted to take advantage of that. That helps us not only on the base from a 3,000 boe perspective, but also on our growth volumes too.

It does give us that ability to take advantage of additional growth volumes too. To my point, we would view that as kind of a short-term in.

It's not something we can really roll into go-forward plan per se, again, very very beneficial from that perspective. We're not going to be rolling in those kind of egress optionalities going forward, but we will continue to take advantage of it where we can.

Perfect. Then I guess related to hedging and Thanh, this will be for you.

Following the Veren deal, you talked about a target about diversification for gas. How can we bridge, just from a timing perspective, how do we bridge kind of this 2026 diversification where you're 50% exposed to AECO, compressing that down to a quarter on the target date?

How do we bridge that over time? Is there kind of interim targets on that target date, if that makes sense?

Thanks for that, Travis. I think the way that we think about diversification is very similar to the way our strategy is from a hedging perspective, right?

We'll continue to layer on incremental positions to be able to get that targeted 50% exposed outside of AECO. What you won't see us do is take these big positions one way or the other, and what we're trying to do is mitigate risk versus increase that.

The one that we did with Centrica is a good example where it was 50 million a day. That's roughly 5% of our total gas volumes there.

As we think about moving into 2028 here, '29, I think over the next two to three years here, we'll have lots of opportunities, whether it's on the financial or the physical side, to be able to price diversify. Then obviously, we've been able to see the benefits of that both in the fourth quarter of last year, as well as the first quarter of this year here, where we realize a significantly higher price than AECO.

It's absolutely at the forefront here, Travis, and our marketing team is well underway in terms of being able to move us towards that 50% sometime in 2028,

2029. Awesome.

I'll turn it back. Thank you.

Hey, guys, thanks for the time. It's pretty obvious we've seen an increase in large-scale M&A in Canada over the past several quarters, including Monday's announcement.

Grant, I just wanted to get your high-level thoughts on just the overall M&A landscape for the industry and also where you think Whitecap fits into the equation. Obviously, the company participated in that consolidation.

Just wanted to gauge your appetite for both larger-scale or smaller-scale acquisitions looking out over the next few years.

Phillips, thank you. The Shell-ARC announcement, I think has put a very much a limelight on what is taking place in the Canadian sector.

There's good reason for that. We, on a relative basis, if we can get this right with the policies and regulatory environment in Canada where we can deliver our products to international markets and further into the United States of America, I think the consolidation will continue, both small-scale and large-scale.

Large-scale M&A activity, there's fewer and fewer candidates out there for large-scale M&A activity. With respect to where we fit on large-scale M&A activity, we talked about, as I referenced earlier, about being counter-cyclical and making sure that we have a strong balance sheet for setting ourselves up for opportunities in the future, whether it's large-scale or small-scale.

Participating in that, I think that we're going to see and continue going to see, because of the inventory set and the quality of inventory in Canada, specifically, people are hyper-focused on the Montney and Duvernay at this particular time, but there's other assets in Canada that are very strong as well. Small-scale acquisitions will always be on our radar for consolidating in and around our existing assets.

That will always be as part of our DNA that we do love where we can own our assets 100% and each one of the areas, the high-netback areas, and uncomplicate our business into the different facilities and infrastructure we have. We'll continue to look at that.

I think Canada is unbelievably well set up with the asset duration and quality we have. If the investing environment continues to improve through regulatory reform, I think Canada can be very well served from an oil and gas perspective.

That is really good color. Thank you for that.

Then just to clarify the comments on the 3,000-a-day of volume boost at Glauconite, sounded like your comments implied that that's not necessarily repeatable. Did you mean that that was temporary capacity that opened up, or is that sort of permanent capacity that's opened up, but it's not, I guess, further gains like that aren't really repeatable?

Hey, Phillips, it's Chris here. That's right.

From the Glauconite perspective, again, just to reiterate my comments, and we'll continue to use optionality and egress when it does present itself. In the case of the Glauconite here, we were expecting that service to be filled by some other producers.

The case turns out that it was not filled by a third-party producer, we took advantage of that. Going forward, we have not baked in additional upside from a Glauconite egress perspective.

However, we have put forward additional base and growth volume outperformance through the rest of our conventional play,

so. Perfect.

That makes perfect sense. Thanks so much.

Morning, guys, and congratulations on the performance this quarter. Just thinking about Lator and sort of the rollout here, what are the key items remaining to gating of this asset, and what does sort of the evolution of the production look like here going forward from a timing perspective?

Hey, Patrick. With respect to remaining work, it's just to finish construction of the facility there.

Like we said, 70% complete is definitely a nice place to be when we're looking at again that Q1 startup. Really just following through.

The reason we did highlight in the prepared remarks there that the major equipment being delivered is just to give a nod to the fact that there are some longer-lead items out there in the world these days, particularly drivers on compression that are challenging some timelines in some facility buildout, and that's a global thing. That's just draw on rotating equipment with demand coming for power generation associated with all the buildout on AI and whatnot.

As I say, we put that in the remarks there to note that we're through that. Compressors are there on lease.

They're spotted on piles, and they're ready to go. Ultimately, yeah, like we said there, materially de-risked for our Q4 on-prod.

Then with respect to the production profile there, it's anywhere from 12 to 18-month ramp to production. Again, that's intentional.

Probably worth noting there, too, that while we have the ability to ramp faster if we wanted to, we enjoy the optionality to be able to deploy our capital throughout our asset base, which we're doing right now, so that we don't have to ramp that facility right up to the 35,000 to 40,000 boe a day on Day 1. We disperse the capital throughout the land base, level-load not just the operations themselves, but then, of course, the associated gathering and processing facilities, and allow for optimization that way in that 12 to 18-month period.

Great. Then maybe with respect to the hedge book here and thinking about the backwardation and the time spreads out there, you guys have been fairly disciplined and regimented about hedging out into the future.

How does the current environment sort of shift your strategy so you can preserve some of that upside?

Patrick, thanks for that question there. Our strategy for hedging really doesn't change, right?

What it's meant to do is stabilize our cash flows in a low-pricing environment there, and it's not meant to be speculative. We certainly have a view on where commodity prices are, but what we're trying to do is lock in the ability to pay for our dividend as well as maintain our production.

So 25% to 35% is what we're targeting over a two-year period of time here. As we think about even getting up to that 35% there, the ability to stabilize our cash flows, but also allows our investors to participate up to 65% on the upside there.

We feel very comfortable about this strategy on a long-term basis, and the certain dynamics haven't changed that strategy.

Thank you very much.

Thanks, Patrick.

Thank you, Sylvie, and thanks to each of you on the line today who continue to support us. From our entire management team, I want to once again thank our entire Whitecap staff and contractors for your dedication and efforts on delivering a very strong first quarter.

To our shareholders, we look forward to updating you on the progress through the remainder of the year and into the future. All the best to each of you, signing off for now.

Cheers.