Baytex Energy Corp. Q1 FY2023 Earnings Call

Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp., First Quarter 2023 Financial and Operating Results Conference Call. The conference is being recorded. I would now like to turn the conference over to Brian Ector, Vice President, Capital Markets. Please go ahead.

Thank you, Ariel. Good morning, ladies and gentlemen, and thank you for joining us to discuss our first quarter 2023 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 and Sustainability 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. And 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, and good morning, everyone. I'd like to welcome all of you to our first quarter conference call. Before discussing our Q1 results, I want to provide a brief update on the Ranger acquisition, which is expected to close late in the second quarter. The transaction materially increases our Eagle Ford scale, while building a quality operating capability in the premier Texas Gulf Coast basin. We believe the combined company will deliver a powerful combination of substantial free cash flow and increased shareholder returns on a per-share basis. Importantly, on a pro forma basis, we will be in a strong financial position that is supported by significant liquidity and a balanced note maturity profile. Since announcing the transaction on February 28, we've achieved a number of key milestones. On April 10, we filed our information circular and merger proxy statement for our annual and special meeting to be held virtually on May 15, and these documents can be found on our website. We encourage all shareholders to vote in advance of the cutoff date of May 11. On April 12, we announced a proposed USD 750 million private offering of senior unsecured notes due 2030. We subsequently upsized the offering to USD 800 million on strong demand. Closing occurred on April 27 and the notes bear interest at a rate of 8.5% per annum. This was a key part of our financing strategy for the Ranger acquisition, and we are very pleased with the support we received from fixed income investors. Lastly, April 13 was the expiration of a waiting period under the Hart-Scott-Rodino Antitrust Improvements Act, which satisfied one of the conditions of the merger. I'm also pleased to announce that T.J. Cepak will join Jeff Wojahn as one of the two independent directors from Ranger we intend to appoint to the Baytex Board of Directors. Behind the scenes, we are working seamlessly with Ranger to ensure a smooth integration at closing and beyond. We remain committed to allocating capital efficiently to generate meaningful free cash flow. For Baytex stand-alone excluding Ranger, our 2023 production guidance range is unchanged at 86,000 to 89,000 BOE per day, with budgeted exploration and development expenditures of $575 million to $650 million. Based on the forward strip for 2023 for Baytex stand-alone, we expect to generate approximately $115 million of free cash flow in Q2 '23 and approximately $325 million of free cash flow for the full year 2023. Following the closing of the merger, we will provide revised guidance for 2023. I'll now shift to our Q1 results where we continue to deliver on our operating and financial targets, which included strong results from our Peavine Clearwater development. Production during the first quarter averaged approximately 86,800 BOE per day, which was up 7% from Q1 '22. We delivered adjusted funds flow of $237 million or $0.43 per basic share and net income of $51 million or $0.09 per basic share. Exploration and development expenditures totaled $234 million in Q1 2023, 38% of our budgeted full year expenditures, and we participated in the drilling of 118 gross, 96.6 net wells. Our 2023 exploration and development program is heavily weighted to the first quarter, which is expected to drive strong free cash flow generation over the balance of the year. Operationally, the highlight continues to be our Clearwater development. We generated production of just under 12,000 barrels per day in Q1 '23. The first 12 wells from our 2023 drilling program at Peavine generated an average 30-day initial production rate of 661 barrels per well per day. In the Pembina Duvernay, we drilled 4 wells of a planned 6-well program. The remaining 2 wells will be drilled during the second quarter. Completion activities for the 2, 3 well pads will commence late in the second quarter. This is early-stage high netback light oil resource play. I now want to spend a couple of minutes discussing our shareholder return framework. In 2022, we made a commitment to return 25% of free cash flow to shareholders through a share buyback program. We executed on this program in 2022, repurchasing 4.3% of our shares outstanding. Upon closing of the merger, we intend to increase direct shareholder returns to 50% of free cash flow generated by the combined company, allowing us to increase the value of our share buyback program and introduce a dividend. Our share buyback program was placed on hold at the beginning of the year due to the pending merger, but will recommence following closing. To meet our shareholder return commitment, we intend to include 25% of the free cash flow generated from January 1, '23 until closing in our 2023 share buyback program. Our existing normal course issuer bid is set to expire on May 8, 2023. Following the closing of the merger, we intend to file an updated NCIB application with the TSX for a share buyback program representing approximately 10% of our public flow. In addition, we will recommend that Baytex pay a quarterly dividend of $0.0225 per share or $0.09 per share annualized. The initial dividend is expected to be paid in October 2023. To summarize, we delivered strong operating and financial results during the first quarter, consistent with our full-year plan. We are on track to deliver substantial free cash flow in 2023, and we are excited to progress the Ranger acquisition, as we build an even stronger North American energy company with a high-quality, diversified oil-weighted portfolio across the Western Canadian Sedimentary Basin and the Texas Gulf Coast. And now, operator, we are ready to open the call for questions.

Our first question comes from Amir Arif of ATB Capital.

I have a couple of quick questions. Regarding the hedges, I noticed you increased your oil batches from about 10,000 to 15,000 barrels a day. I understand you were looking to raise your hedges as you finalize this transaction. What is the target range for the volumes you plan to hedge after the deal?

Yes. So this is Eric. Amir, thanks for the question. I'll hit at a high level, and then I'll pitch it to Chad Kalmakoff. We are looking to get up to on a pro forma basis, approximately 40% of net oil production hedged. The basic structure of those instruments, and it’s important to understand this, is that these are going to be wide 2-way collars, generally, $60 puts, $100 calls and you'll see this continue to manifest itself in the structure. Chad, over to you to add anything you might want to add in terms of just how we intend to…

Sure. Thanks, Eric. Yes. So as Eric said, we're looking to have 40% of the production hedged for the next 12 months post-closing transaction, really targeting that $60 floor. We have a fair bit done today; Ranger has been active in their hedge book through Q1 here. So come to close, we'll have the opportunity to kind of restructure a little bit of their hedge book or kind of a way hedges in as we see fit. But yes, again, looking kind of to the absolute $60 floor, and then kind of getting as close as we possibly can. On a go-forward basis after that, I think as we reduce leverage below the 1x, we'll kind of reduce that hedging target. So at 1x, think about it at 40%, 0.9x, kind of 30% and then kind of working a way down as we get to that debt target of the $1.5 billion, which kind of represents about 1.6x at a $75 rule.

Got it. That's helpful. For my second question regarding guidance, I understand that pro forma guidance on the combined company will be released after the deal closes. I'm curious about the differing approaches of companies that acquire assets. Some slow down operations to generate free cash flow, while others view undercapitalized non-core assets as opportunities and accelerate capital investment. Given that Ranger is a focused, preferred producer, what are your thoughts on the pace of capital investment compared to Ranger's previous capital program?

Yes, thanks, Amir. We're planning to slow down a bit to maintain consistency with our portfolio balance and aim for about 4% organic production growth annually. Ranger has been growing faster than that, and we believe this approach will benefit us for several reasons. It will enable our team to focus more on developing deeper technical insights and enhancing operational efficiency rather than pursuing rapid growth. We're considering operating with around two rigs, potentially bringing in an extra rig occasionally. Overall, we will manage the asset to grow at a modest pace rather than matching Ranger's previous growth rate. This strategy will free up resources and talent to concentrate on reducing costs and enhancing operational efficiencies. Additionally, we believe that evenly distributing our assets across the portfolio will yield the best operational efficiencies and synergies. This approach won't be exclusive to Eagle Ford; we plan to apply it across our operations, focusing on optimal efficiency and capital use. Therefore, we're looking to slow things down slightly, which will help align several factors effectively.

That's great color, Eric. And then just one final question for me. Just on that new Clearwater well that you had, could you give us a sense of what the capital cost is on that well and just initial decline rates you're seeing from that 30-day IP rate?

Yes. I'm not sure that the 30-day IP or the production so far that we've actually even been able to formulate or hang off a decline. So it'd be too soon to know. What I will say is that it's basically half a lateral length that's this part of our Clearwater plan is going to be entering delineation, which is the second phase of kind of 4 phases of commerciality: exploration, delineation, demonstration, and development. And this reservoir, this accumulation is higher pressure than Peavine. Peavine's higher pressure than Nipisi and Marten Hills. We see strong mobility and high recovery. So we're really encouraged by all of that. And I think the other thing that makes this really interesting for us is we have an operating team in place, gas, and water handling facilities in place. The proximity to Edmonton and market optionality is really impressive. So for lots of reasons, we're excited about this play. I think the resource itself as a subsurface resource quality is exciting. And there's going to be more to talk about, but I'm actually not sure we have sufficient real data collected yet to actually hang off the decline curve on this well.

Okay. Do you have a sense of the well cost, even if it was just half the lateral in terms of...?

Oh, yes. So well cost is going to be, I would say, CAD 2 million. It’s very much in line with what you would expect at Peavine.

Our next question comes from Menno Hulshof of TD Securities.

I'll start with the Duvernay. It sounds like completion activity is set to kick off pretty shortly. With that in mind, do you feel like you're still on track to make a decision on how the Duvernay fits in by early 2024?

Yes, we do. So Menno, thanks for the question. We do feel like we're on track. These 2, 3 well pads have gone right to plan. And we're very excited about what we've seen. So data collection doesn't just happen during stimulation and flowback. It also happens during drilling. And we've drilled 3 different laterals. We better understand in these areas now 2 pads, 3 laterals each of 3 wells each better understanding the variability of the reservoir in these areas in terms of drilling quality and things like resistivity and gamma, those formation evaluation data that you collect while drilling. And so we're pretty excited about what we've learned. Again, the actual operation drilling, casing, cementing, the quality of zonal isolation has all gone really, really well, very proud of the team for executing to plan. And we're really excited now. We've got to get breakup behind us, and then we'll put the balance of our design of experiment in the ground through a stimulation, drill out, flowback, and we'll have the information we need to better understand and really, I think, expand our characterization and booking across a much larger cross-section of our aerial extent of our Duvernay acreage.

Okay. And then just to follow up on the Eagle Ford, what are your options on your non-operated acreage? Is status closed still the most likely scenario? Or could we see some adjustments there as well?

Well, I think when you think about kind of what’s going on with our relationship with Marathon, it’s really fantastic. We talk to those guys all the time at every level of the operation. We represent a significant portion of working interest in the AMI. And it’s important to us; it’s important to them. I think we represent something like 20. Our production is not insignificant relative to Marathon’s production. I think you probably read in their release, I think they produced 144,000 BOE a day out of their Eagle Ford assets on a net basis in Q1, and we produced 26,000 BOE a day. That’s not insignificant. It’s like 1/5 or 1/6, and that’s pretty meaningful. We have a great relationship with them. We review the data very carefully that we get. They work very well with us, very openly with us. And they’re a very good operator. So we’re happy with the way the asset is performing. And now that we’ve got this Ranger operating capability very close by, I think what you could expect is that we’ll start working more closely with the Ranger team, who has worked closely in their own right with Marathon in and around the Ranger lands to start increasing our own operated working interest in and around our own lands, and using our working interest in the AMI as currency that is kind of in short swapping and trading to increase both companies operated working interest. You do so on a dollar value equivalent basis; it’s just good for everyone, right? This is the way operators with large interest in each other’s operation sort of get out of each other’s hair. And given the quality of the relationship and the quality of the resource on both sides, I feel really good about that. So these swaps and trades, I think, are going to be a meaningful part of increasing our operated working interest in exchange for Marathon increasing their operating working interest, and it is going to be good for everyone all the way around. So that’s what I would expect to see; more coordination, more close cooperation, and it’s a great partnership. So we think that’s going to be a good catalyst in the Gulf Coast kind of over time and all the way around.

This concludes the question-and-answer session from the phone lines. I'd like to turn the conference back over to Brian Ector for any questions from online.

Okay. Great. Thanks, Ariel. And yes, we do have a couple of questions that have come in via the webcast. And so the first one, I'm going to turn over to Chad Lundberg, our Chief Operating Officer, for a little more color on the economics in the Duvernay. And the question is, what are the IRRs payouts and recycle ratios that we would see in the Duvernay development, maybe at different scenarios of WTI prices, Chad?

Thanks, Brian. To address the earlier question, I’ll start with the figure of $70, which is our current position. At this price point, we achieve an 80% rate of return, about a 3x recycle ratio, and a payout period of 16 months. When considering fluctuations in oil prices, for every $10 change in West Texas Intermediate pricing, we see approximately a 30% variation in the rate of return, a half turn change in recycle ratio, and a potential 4-month shift in payout. The key takeaway is how this aligns with our overall portfolio strategy. Peavine clearly offers the highest returns, followed by Eagle Ford and Lloydminster, our cold flow heavy oil area. The Duvernay fits nicely below those. Additionally, if we broaden our perspective to include unconventional resources, we find that they present very attractive and competitive returns across North America.

Great. Thanks, Chad. Next question from the webcast, and this is for back to Eric and a little bit more elaborating on the range of assets. Are there meaningful as opposed to incremental opportunities to improve well productivity of the Ranger assets on closing of the merger?

Thank you, Brian, for the question. I see both incremental and significant opportunities for improvement. This ties back to my earlier comment, but I’ll expand on it. In companies like Ranger and others I’ve worked with, when you’re growing quickly, it’s essential to remain very lean, especially at a smaller scale. As we grow the business, we emphasize executing our growth programs effectively. As I mentioned earlier, we are taking a step back to align our pace of growth with a target of low to mid-single digits, pointing to around 4% organic production growth per year. To achieve this, we’ll need just over 2 rigs operating throughout the year. By slowing down a bit, we can leverage broader resources from our Canadian operation, particularly in and around Duvernay, along with other resources we’ve explored. This will combine with the excellent performance Ranger has shown in recent years under the new management since late 2020, which has significantly improved performance since 2021 and 2022. We believe there is still more to achieve. There are opportunities for more active geosteering to ensure we stay in the highest quality reservoir and using real-time drilling data to maximize that. The team has done a commendable job, but in rapid growth, it’s easy to overlook opportunities. There are enhancements we can make in stimulation design to increase intensity. The team has already done well, but we believe further improvements can be made through applied data science, including machine learning. We’re eager to collaborate with the technical team at Ranger and combine ideas together. I’m impressed by what has been achieved in the last couple of years, demonstrating that these assets can exceed prior expectations. However, I still see incremental opportunities to enhance this trajectory. For reference, I’d like to highlight a slide from our Baytex and Ranger presentation, particularly Slide 9, which illustrates year-over-year performance improvements. You can see that the 2023 wells have significantly outperformed those from 2022, and those, in turn, are better than 2021. Additionally, comparing against the best operators in the region shows our performance is continually improving. Beyond drilling and stimulation, we also need to consider the nuances of pressure, volume, temperature, and how petroleum fluids behave as they move through the reservoir. We plan to use sophisticated analysis techniques to manage reservoir pressure effectively, maximizing oil value extraction. Slowing down somewhat allows us to focus our talented Ranger team on these intricate technical and analytical aspects. Thank you.

Okay. Eric, another question for you, sort of pro forma Ranger. Can you comment on pro forma free cash flow for the first 12 months following the close of the Ranger acquisition? Generally, what are your expectations?

Yes. So at $75 WTI, which we think is a very reasonable price file, you just take $75 flat out in time, and this is on a combined entity. So I'll also set a benchmark for WCS diff if you use the WCS differential to WTI at $17.50. So $75 is a benchmark TI and $17.50 as the basis dip to WCS. And then you roll the company together pro forma. In the first 4 quarters after close, the combined business will generate $1 billion a year of free cash flow. That $1 billion a year will be allocated 50% to debt pay down. So that's $500 million per year to debt pay down, and $500 million per year to return of capital to shareholders.

And Eric, this relates to the question about free cash flow and its allocation. Do you think the current share value reflects our future growth expectations? What actions will be taken to align the share price more closely with your expectations for the business?

I don't believe our current share price accurately reflects the value I see in this business. I think we are significantly undervalued, which is exciting because it presents many opportunities for those of us on this call. We aim to unlock that potential by focusing on our operations and finding more in bill. Our business encompasses 1.7 million net acres of HBP lands, and I assure you there is more to be discovered. We have been actively engaged in an organic exploration program throughout all of our lands, and Morinville is just one part of an ongoing effort. Another essential aspect is that we will continue returning capital to shareholders by repurchasing and canceling shares, as we did last year. As this business scales and generates more free cash flow per share, we will be able to allocate a larger portion of that cash flow toward buybacks. This dynamic creates a natural upward pressure on all per-share metrics, which will eventually reflect in the share price. While it may take some time for this to occur, I anticipate natural appreciation in the share price stemming from effective execution and the discovery of productive, high-quality assets within our portfolio. If the share price does not align with our intrinsic value, it indicates market inefficiencies that lead to a discount. We plan to take advantage of this situation by utilizing our free cash flow generation to buy back shares at a lower price. I'm genuinely excited about the business and the potential it has today. The current inefficiencies in the oil and gas industry, especially in North America, are creating opportunities where we can capitalize on mispriced assets, and we intend to do just that by repurchasing our shares at this discount.

We'll take a couple of more here on the webcast, and we've had a pretty tremendous response to adding this to our quarterly conference call. Eric, are there any meaningful non-core assets that the combined company might be looking to divest? And second part, any meaningful reduction in drilling costs or relaxation of inflationary pressures?

Yes. I will address the first question and then let Chad Lundberg answer the second. We've been considering our portfolio strategically, and I'm referring to a specific slide in our rollout deck that's been very useful in these discussions. If you look at the lower left section of Slide 10, which shows our portfolio at a $75 WTI benchmark price, you can see notable performance from our Peavine Clearwater area, our Karnes acreage in the Eagle Ford, as well as the Ranger Eagle Ford lands. As we assess the portfolio, keep in mind that we might not be looking at whole assets like Duvernay or Viking, but rather breaking down each asset into segments or tiered reservoir areas, such as Tier 1, Tier 2, and Tier 3. We focus on allocating our capital to the highest returning assets that can effectively utilize that capital. If we maintain 4% annual production growth and a 50% reinvestment rate, which provides substantial free cash flow, it also implies that some assets within our portfolio may not attract capital. In a discounted cash flow context, those assets could be valuable 6, 8, or even 10 years out. They may not compete in our portfolio but could be attractive in someone else's. If they can secure capital funding sooner elsewhere, they would be more beneficial for our shareholders if sold rather than retained. This forms a systematic approach to corporate development and portfolio optimization that we have been implementing, though the addition of our significant Eagle Ford asset has prompted a reevaluation. To sum up, we're focused on parts of major assets rather than entire major assets. Thank you for the great question.

And just on to the inflationary question. So I'll just anchor everybody to where we are today. So as you recall, we picked up about 25% inflation through to the end of 2022. That's based on the lows through '21. We budgeted '23 with an incremental 5% to that. So net-net, we're running the year at about a 30% overall increase over the past 2 years. We're starting to see some relief in our tangible items, but not really as much in the cost of the services themselves. So for example, casing that nearly doubled through that time period is off about 15% as we sit today. Diesel, another one that climbed quite readily through the time period is off about 35%. So that's providing relief to our overall AFEs. I think in the U.S., we're also seeing some relief with respect to rig rates just notionally with gas, seeing some weakness compared to WTI as well as our frac fleets, not overly meaningful yet, but certainly not the large step changes that we have seen through 2022.

Thanks, Chad. And I'm going to take 2 more questions here. The first one, Eric, is Baytex considering a reverse stock split either before or after the merger with Ranger?

It's a great question. There's a lot to be considered. Stock splits, stock consolidations, these are, by their very nature, neither accretive nor dilutive. It’s just arithmetic, right, you're dividing or multiplying to affect a particular targeted share price for reasons related to kind of the large or broad North American investment community and actually even beyond that, U.K. and Europe and so on. But the point is you want to try to attract the broadest possible investment community. And sometimes share prices that are low because total shares outstanding are high, can fall below a certain floor in terms of what funds can buy just based on certain funds criteria. And so that might be a motivation to engage in a stock consolidation, which would take up the share price and take down proportionately the number of shares outstanding. Again, neither accretive nor dilutive, but pretty straightforward arithmetic. We have not spoken with the Board directly formally about that. And so I wouldn't expect it to happen. It will certainly not happen in conjunction with the merger or ahead of the merger. So that's not something we're contemplating. We do believe that there is an opportunity. And if you've ever been involved in an IPO, you know that investment bankers spend a great deal of time with their clients targeting or figuring out what is the best initial price. And it's some of the same dimensions that go into this conversation. What I will say in the near-term is we haven't had the conversations with our Board. We do understand some of the capital markets dynamics. If it happened, it would be thoughtful and would be targeted toward a price that might be in the middle of a family of our closest peers in terms of our North American E&P community. So you could almost guess at what that value might be. But again, we have no formal plans to do so.

Okay. Thanks, Eric. And last question for today's call. Your thoughts on crude marketing in the WCS-WTI differential?

It has been encouraging to see the WCS-WTI basis differential compress; it has improved somewhat over the past couple of months and this quarter. The first quarter did not reflect this because some of the changes occurred after the end of the formal Q1 calendar. We expect the second quarter to show a significantly lower basis dip in all the numbers. You'll notice this trend among all our peers who report on Q1 with WCS exposure. The TMX project will certainly assist in this regard. Adding egress to a producing area like the WCSB will have a positive impact. While we are not an anchor tenant and lack firm transportation on TMX, the increased egress from the basin suggests that the WCS-WTI differential is likely heading toward pipeline economics dictated by the mainline to the Gulf Coast. The economics for piping to the Gulf Coast fall within the $10 to $12 range, which we believe may represent an equilibrium price over time. There may be occasions when the price dips lower due to specific temporary factors, and we will aim to take advantage of those opportunities. We are closely monitoring the marketplace, tracking the progress of TMX, and observing line fill, which we expect to occur in Q4. From what we understand, TMX should be operational in Q1 or Q2. This outlines our perspective, and we do anticipate a shift toward the pipeline economics relating to the Gulf Coast, which will influence the WCS basis dip over time.

Okay. Great. Eric, thank you for that. And operator, thank you. Thanks, everyone, for participating on the phone lines and via the webcast today, and this will conclude our first quarter conference call. Have a great day.

Thank you, everyone.

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