Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp. First Quarter 2024 Financial and Operating Results Conference Call. As a reminder, all participants are in listen-only mode and the conference is being recorded. After the presentation, there will be an opportunity for analysts to ask questions. I would now like to turn the conference over to Brian Ector, Senior Vice President, Capital Markets and Investor Relations. Please go ahead.

Thank you, Ishia. Good morning, ladies and gentlemen, and thank you for joining us to discuss our first quarter 2024 financial and operating results. Today I am joined by Eric Greager, our President and Chief Executive Officer, Chad Kalmakoff, our Chief Financial Officer, and Chad Lundberg, our Chief Operating Officer. While listening, please keep in mind that some of our remarks will contain forward-looking statements within the meaning of applicable securities laws. I refer you to the advisories regarding forward-looking statements, oil and gas information, and non-GAAP financial and capital management measures in yesterday's press release. All dollar amounts referenced in our remarks are in Canadian dollars unless otherwise specified. Following our prepared remarks, we will be taking questions from the analysts. In addition, if you are listening in today via the webcast, you will have the opportunity to submit an online question, and we will do our best to answer all questions submitted. With that, I would now like to turn the call over to Eric.

Thanks, Brian. Good morning, everyone, and welcome to our first quarter 2024 conference call. In the first quarter, we safely and efficiently executed the largest exploration and development program in company history, and delivered operating and financial results consistent with our full-year guidance. We are off to a strong start in 2024 and expect to deliver substantial free cash flow and meaningful shareholder returns over the next three quarters. We increased production per share by 15% in Q1, 2024, compared to Q1, 2023, with production averaging more than 150,600 BOE per day, 84% oil and NGLs. We drilled 83 net wells with 13 rigs running at the peak of the quarter and E&D expenditures totaling $413 million, one-third of our guided full-year expenditures. Our 2024 guidance remains unchanged with E&D expenditures of $1.2 billion to $1.3 billion and production of 150,000 to 156,000 BOE per day. Based on the forward strip, we expect to generate approximately $700 million of free cash flow in 2024. Our strong free cash flow profile reflects the efficiency of our E&D program, higher forecast production volumes for the remainder of the year, and improved crude oil realizations in Canada and Eagle Ford. In Canada, we are benefiting from the completion of the Trans Mountain Pipeline expansion and increased oil export capacity, which is contributing to narrowing basis differentials out of Western Canada. In Eagle Ford, we benefit from our exposure to premium U.S. Gulf Coast pricing for our light oil and condensate production. We intend to allocate 50% of free cash flow to the balance sheet and 50% to direct shareholder returns, which includes a combination of share buybacks and a quarterly dividend. I'd like to now turn the call over to Chad Kalmakoff to discuss our financial results.

Thanks, Eric. In Q1, adjusted funds flow per share was $424 million, or 52% per basic share, which is a 21% increase compared to Q1 last year. The first quarter is our highest capital spend quarter of the year, which sets the stage for a strong free cash flow and increased shareholder returns for the balance of the year. Our current normal course issuer bid allows us to purchase up to 68.4 million common shares during the 12-month period ending June 28, 2024. As of May 7, we had repurchased 46.7 million common shares for $253 million at an average price of $5.42 per share, representing 5.4% of our total shares outstanding. Our total debt at March 31, 2024, was $2.5 billion, largely unchanged from year-end, due to our large Q1 capital program and the impact of the weakening Canadian dollar on our U.S. dollar-denominated debt. As I stated, our Q1 capital program has set the stage for a strong free cash flow profile through the balance of the year. A significant portion of that free cash flow will go to debt reduction. In addition, we're actively managing our debt maturities to ensure ample liquidity and flexibility to execute our business plan while our overall debt position is reduced. With this in mind, subsequent to quarter-end, we undertook two significant transactions. Firstly, on April 1, we closed a private placement of US$575 million aggregate principal amount of senior unsecured notes with an eight-year term. We are very pleased with the market support for this offering. The notes bear interest at 7.38% per year and mature on March 15, 2032. Net proceeds from the offering were used to redeem the remaining $410 million 8.75% notes due April 1, 2027, and to repay a portion of our credit facilities. Secondly, we extended the maturity of our credit facilities by two years to May 9, 2028. Again, we had great support from our syndicate, and I was pleased that we could complete the extension of our US$1.1 billion credit facility. The refinancing of our notes to 2032 and the extension of our credit facilities out to 2028 puts us in a great position with respect to our maturity schedule. We have ample liquidity and flexibility to execute our business plans while reducing debt and providing shareholder returns. Turning to risk management, we employ a disciplined commodity hedging program to mitigate the volatility and revenue due to changes in commodity prices. For the balance of 2024, we have hedged approximately 40% of our net crude oil exposure, utilizing two-way collars with an average floor price of $60 per barrel and an average ceiling price of $96 per barrel. For the first half of 2025, we have hedged approximately 20% of our net crude oil exposure, utilizing two-way collars with an average floor price of $60 and an average ceiling price of $91 a barrel. Now I'll turn the call over to Chad Lundberg to discuss the results of our first quarter capital program.

Well, thanks, Chad. I'm now pleased to speak to our Q1 operations, and highlight the significant efforts of our team. In the Eagle Ford, we continue to deliver strong results across the black oil, volatile oil, and condensate thermal maturity windows. In the first quarter, we brought 19 wells on stream, including 15 lower Eagle Ford wells, three upper Eagle Ford wells, and one refrac. When we compare our operated Eagle Ford performance to a data set of over 560 wells sourced from public data, our performance over the last nine months ranks in the top quartile. On a production per lateral foot basis, we are at the top of the second quartile. I'm very pleased with our results, and I'm confident there's more of this to come. We remain focused on optimizing our acreage and our systems. Our 2024 program includes four upper Eagle Ford wells, three of which were brought on stream during the first quarter and are still ramping. We also completed a refrac in our Medina unit that is expected to generate an internal rate of return of over 100%. Additional refrac opportunities have been identified to supplement our capital program. For 2024, we are targeting an 8% improvement in our operated drilling and completions costs for completed lateral foot over 2023. In our Canadian light oil business unit, we completed our 2024 drilling program in the Pembina Duvernay, and executed another successful winter drilling program in the Viking. We were pleased with the efficiency of our two-path, seven-well drilling program in our Duvernay, which saw a 21% improvement in drilling days, measured from spot to rig release and a 10% improvement in drilling costs compared to 2023. Fracture simulation of a three-well pad commenced in April and the four-well pad is expected to commence in June. In our conventional heavy well business unit, Peavine continued to outperform expectations, and we followed up early exploration success with development in Morinville and the greater Cold Lake area. At Peavine, we brought 12 wells on stream during Q1, 2024 and initial well performance exceeded type curve expectations. At Morinville, we brought four multilateral horizontal wells on stream, and targeted the Rex formation, a Clearwater equivalent. In the greater Cold Lake area, we recently brought five Waseca horizontal multilateral wells on stream. I'm very pleased with our first quarter development program, which delivered strong results across the portfolio. And with that, I will turn the call back to Eric for his closing remarks.

Thanks, Chad. I want to take a moment to thank our operating teams. As many recall, we started the year with some really challenging conditions, extreme cold across North America followed by heavy rainfall in Texas. The teams did a great job. They maintained safe and efficient operations, delivered on the quarter, and delivered the largest Q1 capital program in company history, setting us up well for the rest of the year. I want to highlight the expansion of our land base in the Pembina Duvernay. During the first quarter, we successfully acquired approximately 31 net sections of high-quality Duvernay lands on the southern flank of our existing acreage. This brings our core Pembina Duvernay acreage to 142 net sections, providing us with significant inventory and growth potential in what is becoming a very interesting part of the Duvernay. We believe the resource associated with the newly acquired lands is of very high quality. These lands will immediately compete for capital in our portfolio. As I mentioned at the outset, we are building momentum and expect to generate substantial free cash flow and direct shareholder returns this year. We are committed to a disciplined returns-based capital allocation philosophy aimed at driving increased per share growth and returns. Our Board has declared a Q2 cash dividend of $0.0225 per share to be paid on July 2, 2024. And now we are ready to open the call for questions.

Thank you. The first question comes from Menno Hulshof with TD Cowen. Please go ahead.

Thanks and good morning, everyone. I'll just start with a question on the refrac program, where your rates still look to be pretty strong. Can you just speak to the overall economics of that program, including all-in costs? And is it possible that we see your current refrac inventory of 300 increase over time? Thank you.

Hi, Menno. It's Eric. Thanks for the question. Good to talk to you this morning. The economics are strong. So the rates remain strong. The pressure remains strong. All the indications that one would look to, to give early indications of reservoir performance, stimulate reservoir volume, and what might endure over time, all feel very strong to us. And with a refrac, you can apply all the same things, the same diagnostic techniques to forecast as you would with an ordinary well. So that all feels pretty good. We do anticipate that we're going to be able to continue this program moving forward. Candidate selection is very important, as you know, because you don't want to build a refrac campaign that begins to interfere with the balance of the program. So it has to be complementary, supplementary. But the economics are very strong. IRRs in excess of 100%, and all the diagnostics on the Medina well continue to look very strong. So, we're encouraged by this, and encouraged by the validation of the candidate selection criteria as well. So, we do believe we're going to be able to, over time, and at a measured pace, add this kind of supplemental capital and production program at incrementally better capital efficiencies over time. Let me just pause there and, Menno, you can follow-up, please.

Sure. No, that was great, Eric. Maybe I'll just follow-up with a question on future upside. You look to be working a number of different areas here in Canada, especially on the heavy side of things. Which of these emerging plays are you currently most excited about?

Well, Peavine certainly continues to exceed our expectations. And the fact that we're in Q1, having meaningfully exceeded the high end of our guidance range, or the high end of our collar that we had previously put out and maintained, gives us a lot of confidence. We will continue to reiterate this kind of 15,000 BOE day target for Peavine. And then I think to the extent we exceed performance, that'll be a pleasant surprise. And the reason for that is just, because the reason we've outperformed in Peavine relative to the 15,000 is on surprising outperformance in the reservoir. And so, to the extent that continues to happen, there'll be pleasant surprises and upside performance. But we will stick with the 15,000 BOE a day as our kind of go forward plan. Although, I would expect 2024 to continue to run a little bit above that. So Peavine is one we're really excited about. Of course, the Clearwater equivalent, the Rex at Morinville just north of Edmonton, is an area we've put several full-length development multilateral horizontals in. It continues to perform very well, and we're very excited about that. And the Waseca up in the greater Cold Lake area also continues to outperform our expectations. And so, we continue to delineate those plays and continue to be excited about what we learn as we delineate, find the extents and understand the quality and performance criteria of the reservoir itself. And of course, in the North and West quadrant of our Peace River area, we did acquire some opportunities. These would be in the blue sky. It's very early, but we call this play Grizzly and it shows up in our heavy oil portion on slide 21. And we're pretty excited about that as well. But again, it's very early, so it's not as far along as the Rex at Morinville or the Waseca in the greater Cold Lake area. But all three of these are developing nicely, and the team is continuing to put to work. Two geoscience teams across our heavy oil fairway and continuing to find opportunities. On lands we already own and create opportunities where we can extend our land position commercially.

Thanks, Eric. I'll turn it back.

The next question comes from Amir Arif with ATB Capital Markets. Please go ahead.

Thanks, Eric. And a few quick questions for you. Just on that Medina refrac, can you just quantify the actual wealth or the cost of the completion? And I think you did provide a rate of 700 barrels a day, but just curious where it was prior to the frac?

Yes. So Amir, you broke up just a little bit. I think you asked the capital on the refrac and the rate. Is that right?

The incremental rate, yes. To the 700?

Yes, the incremental rate. Okay. So that well had declined to the point where it was, I don't know, I'm going to say less than 50 barrels a day, BOE a day. And so the incremental as we put it on production after the refrac was in excess of 700 BOE a day. So, incrementally it's 650 plus BOE a day. And again, the reservoir pressure indications, ISIPs, treating pressure and other diagnostic tools that we've used, pressure-dependent rates and the like have all indicated that we have touched substantial or created substantial new reservoir fracture surface area. So we think at a discounted price, we've basically completed a new almost 5,000-foot lateral. And I think it was about, Chad Lundberg, US$4 million? Or was that Canadian?

U.S.

Okay. Amir, I think that rounds out the question.

Yes, perfect. And just on the Peavine, just to follow-up questions, to your comments that you made there, the better production is due to the better wells. What's the limitation in terms of being able to grow that further? Is it just surface constraints? Or is it just how much capital you're allocating in terms of your target number of 15,000 barrels a day?

Yes, so the 15,000 is an output, not an input. So that is the consequence of the other decisions we've made. What is actually the constraint is, you know, our relationship with the Peavine, Métis, and in particular, over the years, you know, it's been a, this has been a four, five, six-year relationship in the making. And, we believe engagement, and respectful engagement and doing what you said you were going to do, in terms of managing the relationships with the communities in which we operate, is a key principle. And one of the key principles during the negotiation was our pursuit to understand how much development and at what pace the community would tolerate. And we've understood that, we've continued to engage, to reiterate that. And it's the pace of development today that we have kind of level-loaded our program at, that dictates the current production rate. So it's really constrained not by the quality of the reservoir or by capital, but rather by our license to operate within the community, and our respect for the community relationship.

Okay. That makes sense. And then just shifting over to the Duvernay, I know you've got some new wells that you're completing. Just a large addition of acreage relative to before you get some additional well results, just curious if you can add some color in terms of is that a different part of the Duvernay, or is it the same trend? Are you comfortable enough adding to that position ahead of the well results that you're completing?

Yes, we're actually very excited about the quality of the resource associated with these almost 31 net sections we've added. You probably know this, but for the benefit of the entire audience. There was substantially more acreage posted in the Crown auction than what we bought. So, we were very surgical and intentional about going after the acreage that we wanted. We got the acreage we wanted, all of the acreage we wanted, and we're really excited about the quality of the resource associated with it. So, we'll continue to step up in our five-year plan capital allocation and the pace of development. So next year we had, this year it's a seven-well program, a four-well pad and a three-well pad in our Duvernay. And next year, it's entirely reasonable to expect it to be somewhere north of seven, perhaps nine or ten. And I think that's very reasonable because this is really high-quality acreage, and it's on trend in the same thermal maturation windows and very close to, geographically, very close to our existing position. So we think we've got acreage in the best part of the Pembina Duvernay. We like the reservoir quality we're in. We like the thermal maturation we're in. We like the liquids mix, and continue to make progress on unlocking the secrets of the reservoir, which will include our new 31 net sections.

Okay. Perfect. And then just one final question, just on the hedge book. You've already got a great hedge book for this year, 40% hedge, 60 floors, 98 hundred ceilings. Just as your net debt comes down, can you give us a sense of what you're thinking about your hedging philosophy going forward?

Yes, yes beyond '24. Yes, because as you point out, '24 is pretty well done. We like the shape and character. And 2025 and beyond, it will continue to follow our net and total debt down. And so 40% was kind of predicated on 1.1 times, 1.2 times total debt to EBITDA leverage ratio. And as that comes down under one, we'll continue to reduce the 40% down linearly, really, not in big staggered steps. But essentially linearly by quarter in conjunction with the leverage ratio as it comes down. So 0.9 times might be closer to 30%. 0.8 times might be closer to 20% of net crude exposure, and so on as it comes down. And we'll just follow that leverage ratio out in time, as the debt comes down. So will the need for our hedge book engaged at the same level.

Appreciate the color. Thanks.

Thank you, Amir.

This concludes the question-and-answer session from the phone lines. I would like to turn the conference back over to Brian Ector for any questions received online. Please go ahead.

All right. Thank you, Ishia. We do have a number of inbound questions coming in on the webcast. So, I'm going to try and summarize a few of them and ask members of the team to address each of the inbound questions. There are a number of themes evolving from the questions that are coming in, and most relate to a discussion around capital allocation in our portfolio. So three components, debt, share buybacks in our NCIB program, and dividends. And so, I want to turn the questions over first to Chad Kalmakoff, and I'm going to summarize this. But we talked about having a strong financial position, but our debt really didn't come down in the first quarter. Can you speak, Chad, to our quarter-end debt levels and expectations for the balance of the year, please?

Sure. Thanks, Brian. Thanks for the question. Good question. I think as we reference our strong financial position, it's good to know that we're speaking to more than just our leverage ratio. Truly, the things we look at are like our financial liquidity, our long-term note maturity profile, which I think is the strongest it's ever been in the last 10 years. So looking at our two series of outstanding notes. We have one turned out to 2030, we have one turned out to 2032. I think this is a strong endorsement from our fixed income investors regarding the depth and quality of our inventory. In our most recent issue, the 7.38 notes, the $575 million, the demand for the issue was very strong, which was five times oversubscribed. And again, as we mentioned before, we've turned out our credit facilities as well out to 2028. So that maturity profile is one of the things we reference when we think about our strong financial position. We also, I guess I wouldn't be remiss to say that we do recognize our leverage ratio is higher than we want it to be. So our debt-to-EBITDA ratio, 1.1 times above some of our peers who are typically in that 0.5 to 1 times ratio. I think we just acknowledge that we realize this and debt repayment is a priority for us. 50% of our free cash flow for the balance of the year will be directed to our balance sheet. And with that, we do expect to reduce our overall debt by just over 10% this year. I think lastly, when you look at the quarter, I think a couple of things we talked about. One, large capital program, Q1, would have impacted that. Secondly, maybe not as obvious, we talked about our notes. Those are all U.S. dollar-denominated notes. So at year-end, FX rates would have been about 1.32. They've moved to 1.35. So that $0.03 move increased our debt at quarter-end by approximately $50 million.

And you express it in Canadian dollars, correct?

As a Canadian reporting issuer. Now, that being said, obviously that impacts our debt levels. A weaker Canadian dollar is actually net beneficial to our business. Obviously, the value of our U.S. business in total would have a large increase with the relative weakening of the Canadian dollar. Lastly, as Eric just mentioned, we did have a $35 million land purchase in the New Bernet High prospect is something we're pretty excited about. So those would be the large contributing factors to the non-debt reduction. I'll just conclude by saying we realize investors are looking for some debt reduction, as are we. We are committed to debt reduction and we are confident we'll reach our debt targets.

Thank you. Thank you, Chad. And keeping on the line, I'll repeat this question that came in as well. We touched on the debt repayment plan. And I'll turn this over to Eric for a bit broader conversation on capital allocation. What are our priorities? Debt repayment, shareholder returns, the buyback program versus the dividend?

Yes. So let me unpack that. Our priorities remain 50% of our free cash flow allocated to debt repayment, as Chad Kalmakoff just took us through, and the other 50% to direct shareholder returns. And the direct shareholder returns are biased in terms of the size of that 50% allocated to our normal course issuer bid. In the last three quarters, we've taken out 5.5% of our total shares outstanding, and that will continue. And of course, the other part of that direct shareholder return portion of the allocation is our fixed base dividend. And that fixed base dividend, of course, is currently set at $0.09 per share per year or $0.0225 per quarter per share. And that remains part of the 50%. So I guess what I would say simply is it's 50-50, and you could ask 100 shareholders their priorities, and you could get something like 50 different answers. Some people like more dividends, some people like more share repurchases, and others like 100% to debt. And because we look at it over time and on a balanced and reinforced framework that doesn't kind of whipsaw quarter-to-quarter, we like this 50-50 allocation. We think this threads the needle between pleasing the broadest possible cross-section of shareholders. So let me just stop there, Brian.

And then continuing on the question around the dividends, Eric, are there any conditions where shareholders could expect to see a dividend increase, and would we ever consider a special dividend at some other companies have put in place?

Yes, so special dividends are real challenging for issuers, particularly if they're kind of special one-time dividends, surprises essentially. They're great for shareholders, but it's very difficult for the issuer to get value embedded in the stock because nobody knows how to discount the probability when that will happen and how big it will happen. Now, variable dividends are a different construct around special variable dividends, and if you have a very rigorous formulaic approach to how you go about quantifying the forward variable dividends, that's something I've seen done, and I think that can get priced into the stock. I would say the third thing is on raising the dividends, one of the reasons we started with a modest fixed-base dividend currently yielding, let's call it 1.8%, was to give us the opportunity over time to increase the dividend on a per-share basis and hopefully on a yield basis consistently over time. Now, we haven't so far because we've only been at this now for three quarters, but it is certainly our desire to, over the long arc of time, create a track record of raising our fixed-base dividend and our dividend yield over time as part of our total shareholder returns framework. Now, the last part I'll say on this, it's not specifically around dividends or the dividend question, but when we take 50% of our free cash flow and we allocate it to reducing our debt, even though that's not part of our direct shareholder return framework, it's still meaningfully impactful to share price appreciation because if you assume for the moment that all things equal, the enterprise is going to be able to pay back the share price, the share price is going to be able to pay back the dividend, and that's not going to be a direct shareholder return. If the enterprise value of the business stays the same over time, then every dollar of debt you reduce becomes a dollar of equity increased in the business. This is something we recognize. So, essentially, the full $700 million of free cash flow generated this year goes to direct shareholder returns to the 50% NCIB and dividends, but indirectly, as we pay down debt, goes to share price appreciation because it moves from the debt side of your EV to the equity side of your EV. This is where we really think there's some substantial acceleration or compounding of the benefits. If we buy back 7% or 8% of our total shares outstanding each year and we add to that 7% or 8% a 2% fixed base dividend and then we add to that 2% top line production growth, that's a 12% total shareholder return on the sum of those three parts. And then when you add to it the additional 50% allocation to debt that kind of puts goose and acceleration in that, it's meaningfully north of the 12% TSR. So, that's a fairly fulsome discussion, I think, around the shareholder return framework.

Thanks, Eric. Back to Chad Kalmakoff. Chad, during the quarter, we issued a press release about seeking exemptive relief for our normal course issuer bid. Can you explain the plan and what it relates to?

Sure. Thanks, Brian. That exemptive relief is really to allow us to buy additional shares directly through the NYSE versus the TSX. So, really just kind of directing some of our NTIB to U.S. shareholders versus the Canadian shareholders. We need a relief to do that. Generally speaking, we buy off both exchanges, but we have been a little bit more directed to the U.S. exchange, partly to ensure that we maintain our foreign private issuer status.

Okay. Thanks, Chad. So, we touched on the debt repayment plan, normal course issuer bid, the dividends. Eric, one more question, and this relates to another use of the free cash flow and capital, and that relates to production growth. So, how do you think about balancing current production and cash flow goals versus incremental spending to generate production growth? And what are the tradeoffs as you think about the company's future?

Yes. Thanks, Brian. It's a great question. Those of you who have indulged in our IR deck online know that we've got a 1% to 4% range over the five-year plan, our LRP, and we talk often about 2% per year. It's just handy shorthand for the midpoint of that growth range in terms of top-line production growth per year. The 2% essentially is meant to be just north of flat such that you can, with some certainty, ensure that you don't create back-to-back sequential quarters of negative growth, right? So, because that has negative optics around sequential negative production growth, what you'd like to do is, if you have a quarter that goes down relative to the subsequent quarter, you'd like it to be only one quarter and not a pair of quarters. 2% generally does that if you use shorthand math and given the seasonality of our business and where we operate. And so, we think that's just right. Otherwise, you could just say just barely north of flat. And what does just barely north of flat production mean in terms of maintenance capital? It means you're maximizing your free cash flow generation. And that is our commitment. Our commitment is to allocate our capital to the highest returning projects and maintain the maximum operational efficiency in each part of our portfolio while not growing any faster than necessary so that we can maximize free cash flow generation and allocate that free cash flow to debt reduction, share repurchases, and our dividend.

Okay, thanks, Eric. A couple of questions have come in around the production volumes we reported during Q1, Eric. Can you explain maybe the difference between what we realized in Q1 from a production standpoint relative to Q4 and how that sets us up for the year?

Yes, thanks, Brian. So, Q4 was strong. So, above the high end of our guidance range at the exit and on less capital in Q4 than we anticipated. So, that was a very strong kind of operational outcome for Q4. The thing that's important to keep in mind is the 151, I'll call it, for Q1 was also well within our outlined full-year guidance plan. So, 150 to 156 was our plan, our guidance plan. And the 151 or 150.6 is what we expected in line with our expectations. Now, the difference between the 160 and the 151, it's important to understand there was 4,000 BOE a day in the Viking, 100% oil sold, and the proceeds from that were put to debt in Q4. And so, that accounts for 4,000 of the 9,000. The other part of that drop between 160 and 151 is really related to seasonality and in particular related to our marathon non-op activity in our non-op Eagle Ford, the Karnes Trough, Eagle Ford. Marathon had been working very diligently throughout the year and in particular throughout the summers, Q2 and Q3. But by the end of Q3, it essentially spent the capital they had allocated to the project. And so, in all of Q4, there was no stimulation, no wells turned to sales. And so, naturally, between Q3 and Q1, all the production, particularly the newest production with the highest pressures, released in late Q3 declined off into Q1. And so, that is the other part of the gap. But none of this comes as a surprise, Brian, and this was all within our guidance range, and we continue to reiterate not only our 150 to 156 guidance range, but also the continued growth throughout the quarters of our production. So, let me stop there.

Thanks, Eric. Okay, I want to shift. We've had a number of inbound questions on the webcast related to our operations. I'll start with Chad Lundberg. As an opening question, Chad, how many wells are planned to be drilled in 2024?

Thanks, Brian. So, yes, total quantum of wells drilled this year will be 250. If you reference the investor pack online, that's page 7 of the slide deck, roughly 60 of those are being allocated into the United States, and they'd be for properties both on an operative basis. A hundred of those are in the Canadian side, our light oil business, and then approximately 90 would be the balance of the 250 through our heavy properties. The other thing I would note is just the efficiencies we're seeing as we levelize our ego forward and think about the big machine that we call our assets today. Just the efficiency, you see it in the pressure leaks. We saw a 21% improvement on drill days through the Durban A. That translated and flowed through a 10% cost increase. We're seeing that in the United States with an 8% reduction in EUFAR costs. Largely synergistic with each other, and we're just excited to be able to share across both sides of the border as we think about improving.

And, Chad, just an investor asking us to confirm our 2024 plans at Peavine. The well count, I believe we're looking at for a total of 35 wells this year.

Yes, I mean, Peavine has been a tremendous story, obviously, for those who have followed us since we started back in 2021 with our first exploration and discovery well. This year we've ramped to two rig steady pace program that would be approximately 35 wells. Twelve of those are down in Q1. We're looking at an option to, maybe drop that back to one rig and attempt to drill through break up here. It would still achieve close to the same well count, the 35, but we're excited, again, about the efficiency that we can drive out of the program by just really continuing to think about operating this equipment on a very steady basis. And the crew, the equipment, the efficiency we can drive out of that.

And, Chad, with recent flooding around the Texas area last week, any of our production affected?

No, the short answer is nothing was affected last week. Definitely heavy rains in the greater Houston area. I think, when I think about that production team, they're very good at managing and operating, obviously, in their own acute conditions. No different than in Canada in our coal conditions that permeate themselves through the Q1 time period. But no flooding effects last week.

Maybe a question back to you, Eric, operationally. Production levels that could, we talked about our heavy oil plays. You mentioned earlier, referred to the Rex, the Waseca, Grizzly, even the Duvernay. What production levels could be expected in these heavy oil plays as we move forward?

Yes, so these are, in terms of moving the needle on a base of 153,000 BOE a day, the midpoint of our range, they're not going to be that meaningful. But having said that, the well performance really, really is quite strong. And the economics are really incredible because these, generally speaking, these multilaterals in high quality, competent reservoir don't require liners. They don't require cementing. They don't require any stimulation. These are just long, open hole multilaterals tied into a single well. And so the capital is very modest, I mean, compared to unconventional Duvernay and Eagle Ford, for example. So a couple hundred barrels a day out of each well, and we've got four wells on in Morinville, and I think we've got five wells on in the new Waseca play at Greater Cold Lake. And both of those are in excess of 1,000 barrels a day today. And they're very flat declines, flatter in Waseca than in Morinville because the Morinville reservoir is a little higher pressure. And when you have higher pressure, you generally have higher, early decline rates. But nevertheless, both of those will grow to a few thousand barrels a day each. And on the basis of 153,000 BOE a day in growing, it's modest. But, again, these things are so accretive in terms of economics and nav creation that they're very, very attractive to us. And we will continue to deploy our geoscience teams and our intellectual property across our large heavy oil pipeline to find these where they are.

A two-part question on the Duvernay for you. Any ability to acquire additional land beyond the Crownland purchase from Q1? And part two, what level of production in wells per year could we see from the Duvernay? And what type of growth profile?

Yes, so there's always more you can buy. We're very intentional about where we spend the money. It's got to be, as good as what we've got already or better. And, of course, the 31 net section acquisition we made in Q1 in the Duvernay met that criteria and is immediately executable. That's the other thing. You don't necessarily want to find yourself in a position where you've bought high-quality resource that you can't execute on quickly. And so next year, because we've already finished the drilling, casing, and cementing of our 2024 program, next year we'll actually be deploying capital against not only our existing Pemina-Duvernay position but our new extension to better understand it, continue to inform our technical models, and bring obviously, value forward on that land acquisition. And now in terms of how fast we can grow it, we've steadily ramped activity in our Pemina-Duvernay, two wells per year, four wells per year, six wells per year last year, seven wells per year this year. We're expecting north of seven next year. I'm going to say nine or ten if we're just kind of broad brush strokes here. But it'll certainly be seven to ten. It'll be more than what we've done this year. And we're going to continue growing that. Our LRP contemplates a max of 12 wells per year, but that was before our new acquisition. And so we think we'll be north of that as well. And we think this, as we continue to ramp this and on good results potentially accelerate, because the capital efficiency is very strong and accretive to our portfolio, we would grow this thing, we think north of 20,000 BOE a day over, perhaps a five-year period, perhaps a year or two longer. Some of this is still in the works in our current LRP, but it's a meaningful addition. In fact, with most of the rest of our portfolio running flat, this is where our growth engine is, and we're very excited about that. It's high-quality contiguous position with lots of control, and we're excited about the opportunity to continue deploying capital there, growing the asset and doing so at incrementally accretive capital efficiencies, which will improve our overall business over time.

At a high level, Eric, acquisitions and dispositions, what are we thinking about as it relates to that? What areas would you consider core? And maybe part of that, given the diversity of the asset base, would we consider pursuing asset sales?

Yes, so we sold a portion of the Viking last year. It's a good place to start in this answer because we call those assets 4 again in PLATO, and it was 4,000 BOE a day, and we got $160 million out of that. Now, the challenge was, and the reason those assets were carved out of the portfolio is because they could not compete for capital within our portfolio, and so given that fact, we were left with two choices. We were left with deploying capital against assets that didn't compete in the portfolio, and that capital then, of course, punches below its weight because you've taken it away from an allocation to a higher-performing asset, so that's diluted to your performance. Or you don't allocate capital, and we know that fracture-stimulated reservoirs over time, like 4 again in PLATO and Viking, starved of capital would decline to no value over a couple of years. And so you don't want to starve an asset of capital and allow it to decline to no value. You also don't want to allocate capital to something that doesn't compete, and so you're left with, if it's worth more to the outside world than it is in our portfolio, we should sell it. And so we set a retention value on that basis, and the proceeds were clearly worth more than it was inside our portfolio, so we sold it. We think that's disciplined portfolio management, and we revisit our portfolio every single quarter because market conditions change, differentials change, quality and performance, the quality pricing and so on changes. So we revisit that frequently and continue to reallocate our capital to the highest-returning portions of our business within our portfolio. If something doesn't compete, then it gets considered for disposition. Right now, everything in our portfolio is funded and competes for capital, but should that change, we will run a disciplined discounted cash flow analysis, and we'll set a retention value, and we will test the market. And if it's worth more on the open market than it is within our portfolio, we'll sell it. We think that's disciplined. We think that's the right economic basis upon which to sell assets, and the proceeds of any sale would be applied today to our debt.

Okay, thanks, Eric. Let's revisit really quickly our free cash flow profile for the year. Q1 free cash flow is zero. We talked about that. We say full-year free cash flow at the current strip is $700 million. Why the disconnect between Q1 and the balance of the year, Eric, and maybe a second part of that, is there any reduction in E&D spending to improve the free cash flow profile?

Well, it's a great question. We talked earlier about the 2% top-line production growth year-over-year as being set essentially as close to flat as we feel comfortable because the seasonality of our assets and our portfolio require us to be a little north of flat to avoid things that we think wouldn't be very constructive. So we like 2% per year top-line production growth, and if we reduce E&D capital further, of course, that would have lagging, knock-on production impacts. And these are all very profitable investments. So, everything we're investing in, have IRRs that are substantially north of our threshold, crochets that are substantially north of our thresholds, and are all very economic. And so these are economic investments, and we've set the E&D capital to be as low as it can be, which corollary to that essentially suggests that we're maximizing free cash flow generation. The reason there was zero free cash flow in Q1 is because the size of the capital program in Q1 essentially took all the operating cash flow and committed it to CapEx, leaving nothing for free cash flow. And the reason we did that in Q1 is because we need to get a strong start to the year because we don't always know how breakup is going to treat us, like what is going to happen during breakup in Canada. So we always start very strong on our drilling and completions program to set ourselves up for optionality, depending on whatever happens with breakup. And then if we have good options through breakup, we can then levelize our program and levelize our capital, our production profile, as well as our free cash flow generation. And that's certainly our objective, is to continue to levelize our capital, our production profile, and our free cash flow. It would be ideal, we certainly recognize it, as does the investment community, if we could stay in the market all four quarters of any given year and apply a uniform buyback structure. And that is certainly our objective, and we're working very hard to make that a reality out into the future.

Thanks, Eric. We've got time, I think, for two questions. We're coming up on the hour. There's been a very thoughtful and thorough list of questions coming in today. This is a little different, Eric, one around executive compensation. Your thoughts around executive compensation, a comment around stock options. We don't grant stock options, so maybe just your thoughts on executive compensation and our approach.

Yes, so our approach to executive compensation is to ensure that all of our executives have a substantial portion of total compensation at risk. Our long-term incentive plan is based on a one-year and three-year TSR. Those TSRs are linked to total shareholder returns, and so when the share price underperforms, so does our compensation. So we take a direct at-risk compensation hit when share price underperforms. We think that's the right thing to do. Something like 70% of my own compensation is at risk. And to go beyond that, in the past 15 or 16 months, I've bought well north of 1.1 million shares of Baytex and used personal money, personal family money to do so. And I think that's the right thing to do as well. Insiders need to own the business. We need to feel the pain. So we think at-risk compensation is an important principle. We think insider ownership is an important principle. And we also mark our compensation every year to our peer group. And we are below the mean, below the median on virtually every executive level of the business in terms of our compensation. And so, this is all public information that you can find as you look through public circulars. But I do think it's really important to point out, one, we benchmark it. Two, we maintain a competitive level with our peer group and currently below the median. Or a central tendency of that data set. And three, substantial at-risk compensation with substantial portions of insider ownership.

And last question today, Eric. What has to happen for the share price to reflect the value of the assets? A few investors have reached out today expressing frustration with where we're trading. What are your thoughts on the value creation for Baytex?

Yes, I share your frustration. I understand your concerns. There are several factors specific to Baytex that are impacting our short-term share price performance. One factor is the significant ownership by Ranger Juniper Capital's majority owners. These are knowledgeable long-term energy investors who support our business and the energy sector overall. However, their perceived position as potential sellers, along with a 12% stake in our stock, contributes to what is seen as an overhang on our shares. Unfortunately, this is something we cannot change and must endure. Another factor unique to our stock is the ongoing issue with the Canada Revenue Agency. We have previously discussed this and disclosed relevant information. The current leadership did not create this issue, but we are responsible for managing and resolving it. We have limited the associated risk and are confident in our position based on advice from our tax counsel. Even in the event of an unfavorable outcome, we have mitigated the risk through external insurance, and we feel reassured about this situation. Additionally, it has been nearly ten months since we completed the acquisition of Ranger, and we have successfully integrated their operations while enhancing performance and efficiency. We are pleased with how the team has performed and how well we have been able to blend the assets. However, transformational deals like this do take time to stabilize, which can be challenging. We recognize that our share price has underperformed and are doing everything possible to address this. We are open to discussing this further one-on-one with anyone interested in a more in-depth conversation.

Excellent. I think it's a great way to wrap up today's call. So, Ishia, I think we'll call it there. Thank you, everyone, and thanks to everyone for participating in our first quarter conference call. Have a great day.

This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.