Earnings Call Transcript - BTE Q4 2023

Operator, Conference Operator

Thank you for your patience. This is the conference operator. Welcome to the Baytex Energy Corp. Fourth Quarter and Full-Year 2023 Financial and Operating Results Conference Call. Please note that all participants are in listen-only mode and the conference is being recorded. I will now hand the conference over to Brian Ector, Senior Vice President, Capital Markets and Investor Relations. Please proceed.

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

Thank you, Galen. Good morning, ladies and gentlemen, and thank you for joining us to discuss our fourth quarter and full-year 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 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. On the call today, we will also be discussing the evaluation of our reserves at year-end 2023. These are valuations that have been prepared in accordance with Canadian disclosure standards which are not comparable in all respects to United States or other foreign disclosure standards. Our remarks regarding reserves are also forward-looking statements. 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 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.

Eric Greager, President and CEO

Thanks, Brian. Good morning, everyone, and welcome to our year-end 2023 conference call. I'm excited to discuss our 2023 results and in particular, our results over the past two quarters, which demonstrate the merits of the Ranger acquisition and the strength of our oil-weighted portfolio. Before diving into our results in a little more detail, I want to take a moment and recognize the hard work of our passionate team of high-quality professionals in Houston and Calgary. Our teams have come together to create a new and stronger organization that we are all proud to be a part of. I would like to give a shout-out in particular to our field staff who work under extraordinary conditions at times. We were reminded of that in January with extremely cold temperatures across North America, which was followed by heavy rainfall in Texas. We are grateful to our employees and contractors for their commitment to safe operations and their tireless effort to provide reliable energy to fuel people's lives. Let's turn to 2023. On June 20, we closed the acquisition of Ranger, adding quality scale in the Eagle Ford along the U.S. Gulf Coast and reinforcing a resilient and sustainable business. In conjunction with closing, we increased direct shareholder returns to 50% of free cash flow, which allowed us to increase the value of our share buyback program and introduced a dividend. The remainder of our free cash flow was allocated to debt reduction. In 2023, we returned $260 million to shareholders through our share buyback program and dividend. Our normal course issuer bid allows for the purchase of up to 68.4 million common shares during the 12-month period ending June 28, 2024. Through December 31, 2023, we repurchased 40.5 million common shares for $222 million, representing 4.7% of our shares outstanding. In addition, we declared two quarterly dividends each of $0.0225 per share totaling $38 million. In 2023, we increased production per basic share by 16% over 2022. Production in Q4 '23 averaged just over 160,000 BOE per day, exceeding our guidance for the quarter and up 6% from the third quarter. Production for the full-year 2023 averaged 122,000 BOE per day compared to 83,500 in 2022. For the second half of '23, exploration and development expenditures totaled $608 million, consistent with our plan following the Ranger acquisition. Capital spending during the fourth quarter was 10% below guidance, demonstrating our commitment to disciplined capital allocation. We generated free cash flow of $291 million or $0.35 per share in the fourth quarter and $544 million or $0.77 per share for 2023. Our business improved structurally through the Ranger acquisition with increased exposure to premium U.S. Gulf Coast pricing and improved margins. In Q4 '23, over 40% of our liquids production received WTI equivalent pricing. In addition, we improved our cash cost structure, which consists of operating, transportation, and general and administrative expenses. In Q4 '23, by 12% on a BOE basis compared to Q4 '22. On December 11, we completed the divestiture of Viking assets at Forgan and Plato in Southwest Saskatchewan for proceeds of $160 million. Production from the assets at the time of the sale was approximately 4,000 BOE per day. During the fourth quarter, we reduced our net debt by 10% due to a combination of free cash flow generation, net proceeds from the Viking divestiture, and the impact of a strengthening Canadian dollar relative to the U.S. dollar. We maintained balance sheet strength with a total debt-to-EBITDA ratio of 1.1x. We employ a disciplined commodity hedging program to help mitigate the volatility in revenue due to changes in commodity prices. In 2023, our hedging program generated about $36 million. For 2024, we have entered into hedges on 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. At year-end 2023, we recorded noncash impairments on our legacy non-operated Eagle Ford and retained Viking assets of $834 million. This noncash impairment resulted in a net loss of $627 million or $0.75 per share in Q4 '23 and $235 million or $0.33 per share in 2023. Operationally, the integration of the Ranger assets has progressed well, and we continue to deliver strong results across the black oil, volatile oil, and condensate thermal maturity windows. In Q4 2023, nine operated wells were brought on-stream bringing the total operated wells on production since closing Ranger to 22. The nine wells brought on stream during the fourth quarter generated an average 30-day initial production rate of approximately 1,600 BOE per day, 80% of which is oil and NGLs per well. On our non-operated acreage, there were no new wells brought on stream during the fourth quarter. When we compare these results to a data set of over 1,000 Eagle Ford wells sourced from public data, our second-half performance ranks in the top quartile of all 2023 wells drilled in the Eagle Ford. And because of longer laterals on a production per lateral foot basis, we're in the top of the second quartile. So I'm very pleased with our performance. We continue to optimize base performance and remain focused on strong drilling and completions performance. For 2024, we are targeting an 8% improvement in our operated drilling and completion cost per lateral foot over 2023. In the Pembina Duvernay, we commenced drilling operations in January and to date, have drilled three of seven wells planned for 2024. Completion activities are scheduled to commence in May. We continue to advance our understanding of the reservoir and believe the asset offers significant economic inventory and growth potential. In our heavy oil business, our Clearwater production averaged over 16,000 BOE per day during the fourth quarter, up 48% from Q4 2022. At Peavine, we brought 31 wells on stream during 2023 and initial well performance continues to outperform expectations. In 2024, we will see continued exploration across our heavy oil portfolio with up to 14 stratigraphic test wells planned. With respect to reserves, our year-end report reflects the Ranger acquisition with a meaningful increase in high-value light oil production along the U.S. Gulf Coast. Proved developed producing reserves increased by 49% from 124 million to 185 million BOE. Proved reserves increased by 55% from 264 million to 410 million BOE and proved plus probable reserves increased by 51%, from 438 million to 663 million BOE. In the Eagle Ford, proved and proved plus probable reserves increased 117% and 130%, respectively. Reserves associated with the Ranger assets were consistent with our assessment of the Ranger reserves at year-end 2022. In Canada, we replaced 131% of production on a proved plus probable basis, net of the divestiture of our Viking assets. Overall, we generated a PDP recycle ratio of 1.7x based on a 2023 operating netback of $41 per BOE. As responsible energy producers, we are committed to reducing the intensity of greenhouse gas emissions from our operations. Our corporate objective was to reduce our GHG emissions intensity measured as kilograms of CO2 equivalent per BOE by 65% by 2025 relative to our 2018 baseline set on our Canadian assets. And I'm pleased to report that in 2023, we reduced our GHG emission intensity by 9% and achieved our 65% target two years early. We're in the process of road mapping 2030 GHG reduction targets. As I wrap up my prepared remarks, I would like to reiterate our commitment to a disciplined, returns-based capital allocation philosophy to drive increased per share returns. The three key pillars of our business strategy are disciplined capital allocation, strong free cash flow generation, and maintaining financial strength. Our 2024 guidance remains unchanged with exploration and development expenditures of $1.2 billion to $1.3 billion and production of 150,000 to 156,000 BOE per day. I would note that we expect our first quarter production to be approximately 2,000 BOE per day lower than our budget due to extreme weather conditions across North America in January, which led to production disruptions. In 2024, we intend to continue progressing our Pembina Duvernay, further delineate our Clearwater and Mannville heavy oil fairways, and deliver strong drilling and completion performance in Eagle Ford and Viking. Based on the forward strip, we expect to generate approximately $575 million of free cash flow in 2024. This is up 8% from our budget announcement in December due to an improved outlook for crude oil prices. Our capital program is weighted to the first and third quarters, and as a result, we expect to generate a significant amount of our 2024 free cash flow during the second and fourth quarters. I'm very pleased with the operating results across our portfolio, which has set the stage for a strong 2024. Our Board has declared a Q1 cash dividend of $0.0225 per share to be paid on April 1, 2024. We are well capitalized and remain committed to creating long-term value and increasing shareholder returns. And now, operator, we're ready to open the call for questions.

Operator, Conference Operator

Thank you. We will now begin the analyst question-and-answer session. Our first question is from Greg Pardy with RBC Capital Markets. Please go ahead.

Unidentified Analyst, Analyst

Hi, good morning. This is Rob on for Greg Pardy and thanks for your commentary. My first question just on the Clearwater, production remains strong, coming in above 16,000 barrels a day in the quarter. Do you still believe the 12,000 to 15,000 production range is the right range for this asset? And how are you guys thinking about this moving forward?

Eric Greager, President and CEO

Thanks for the question, Rob. We will continue to mention the range of 12,000 to 15,000. However, I believe it will lean towards the higher end of that range, possibly stabilizing around 15,000 over time. That seems logical. We will keep discussing this as we analyze the performance of the wells, and we will adjust our perspective accordingly. So far, the results have exceeded our expectations. I would suggest aiming for the higher end of that range, with more updates to come.

Unidentified Analyst, Analyst

Great, thanks. That's helpful. And maybe just shifting gears a little bit. Your total debt came down about 10% in the quarter. Will debt repayment remain a priority for 2024? And where do you see your debt at year-end 2024, given the current strip?

Eric Greager, President and CEO

Yes, it certainly will. We really like our capital allocation framework. So 50% of our free cash flow committed to reducing our debt and the other 15% committed to capital return to shareholders. I anticipate that we'll finish 2024 with probably about a turn of leverage. So total debt in the range of our EBITDA, probably, I would say $2.2 billion is probably a pretty decent number. Yes, $2.1 billion to $2.2 billion is what I'm told.

Unidentified Analyst, Analyst

Yes, great. Thank you. That's really helpful. I will turn it back.

Operator, Conference Operator

The next question is from Philip Skolnick with Eight Capital. Please go ahead.

Philip Skolnick, Analyst

Yes, thanks. Good morning. My first question is just with respect to your first quarter production. How should we be thinking about oil production overall versus natural gas? Is your natural gas for Q4 did come in a bit above expectations.

Eric Greager, President and CEO

Yes, you're correct, Phil, and I appreciate your question. For Q1, I expect it will likely fall at the lower end of our range of 150 to 156, so around 150, which aligns with our budget discussions. If it turns out to be between 150 and 151 as we finalize our budget, we may need to make a minor adjustment. I've mentioned about 2,000 BOE per day. For the full year, we should be close to the midpoint of our range, but there is a possibility we might be slightly below what we discussed previously. It could be around 149 or 149.5 as we address the production disruptions caused by the polar vortex. You're correct that we've experienced strong well performance in our Eagle Ford, covering all phases, including natural gas, oil, and NGLs. As I noted in my prepared remarks, the well performance has been top quartile, contributing a significant amount of gas. This has likely resulted in about a 1% change to our total liquids-gas mix in Q4. However, as we move into Q1, I anticipate we’ll return to a more balanced approach regarding our historical trends, aiming for a liquids mix around 84 or thereabouts compared to gas. Overall, I expect things to trend back towards a more balanced trend line.

Philip Skolnick, Analyst

Got it. Thanks. And then my other question is just are there any updates on Mannville and Waseca?

Eric Greager, President and CEO

Yes, so we have continued developing in the Cold Lake area the Waseca and have continued to learn and generate results we can continue to build forward. We haven't released those results yet, but we're encouraged by what we're learning. Certainly, that's the Waseca in the Mannville stack and the Cold Lake area on that new land extension and continued discoveries in that area. Then around the Morinville, the Rex and Morinville, likewise, we've continued to delineate those structures and understand kind of the extent of the structures and the quality of the reservoir, nothing really to report at this juncture in the conversation, but we're continuing to better understand the reservoir quality and better understand the extension structure. And then I think it's important here to point out, we actually made another land extension to the north and west of our Peace River area, an area we call Grizzly that is also exploratory that we feel very encouraged by in our understanding of its prospectivity. So more to come on that, but continued learnings and progress around the Waseca at Cold Lake, the Rex at Morinville, and the Bluesky in Grizzly.

Philip Skolnick, Analyst

Perfect, thank you.

Eric Greager, President and CEO

Thank you, Phil.

Operator, Conference Operator

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

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

All right. Thanks, Galen. And there are a lot of questions coming through on the webcast. So we do appreciate the level of engagement with our shareholders. I'm going to try to get to a number of the questions. If we don't get to your question, then I will follow up with you offline. Eric, you alluded to it in one of the analyst questions but a number of investors are asking about our capital allocation framework, some questions around should we be allocating more to debt repayment. Others are asking, should we be increasing the buyback program. So do you want to just run through maybe a little bit of your thought process around the capital allocation process and what we're doing and what we're thinking going forward?

Eric Greager, President and CEO

Yes, that's a great question, Brian. I appreciate you asking it through the web portal. This is not an exact science, and we continue to engage with our shareholders and our Board. These discussions are interesting and intellectually stimulating because they involve trade-offs and subjective judgments. We favor a 50-50 framework, allocating 50% of the generated free cash flow to our debt. If you consider the debt as a return on that marginal cash flow dollar committed to pay down, the after-tax return is approximately 6%. With a free cash flow yield of about 16%, you have two different capital pools with varying costs. If you were purchasing a car, building a home, or financing a business, you would typically prioritize paying down the higher-cost capital first, in this case, the 16%. This approach guides our decision-making, though there are also dynamics between enterprise value, market capitalization, and how debt repayment affects enterprise value, making it essential to maintain a more balanced allocation than a strict 16 to 6 ratio would suggest. Therefore, we believe that a 50-50 approach recognizes the value of both sides. The bonds are performing well, recently trading at $104, which signals a strong credit profile. This suggests that investing free cash flow into equity buybacks is likely a good focus. I’ll pause there, Brian, and I’m happy to go further if there are more questions.

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

Okay, thanks Eric. Another common theme coming through on the questions does relate to the noncash impairment. So a number of investors asking for maybe just a little bit more of an explanation behind the impairment on the non-operated Eagle Ford and the retained Viking assets. Can you elaborate a little bit for people a little bit of comfort with what we're doing, please?

Eric Greager, President and CEO

Yes. Thanks, Brian. So it's important to understand that, in particular, in E&P, every industry in different businesses kind of run on different foundational structures. Within E&P, what's most important in these businesses is the cash-making capacity of a business. And a non-cash impairment is an accounting adjustment. It's not a cash measure. The cash-making capacity of our business remains stronger than it's ever been. Q4 was a solid quarter, a solid finish to a transformational year, a strong company, significant base of quality assets with lots of opportunities. Our operational performance is better than it's ever been, and we're more diversified and resilient than we've ever been. But what lies underneath those non-cash impairments, those accounting adjustments really is an underlying conversation around provisions to the reserves. So the technical revisions were relatively small, 4% of our opening reserves balance. A majority of those technical revisions occurred on our non-operated Eagle Ford asset. And those were basically founded where we recognized steeper declines on wells drilled after 2017 as a result of tighter spacing. This is something that the industry at large has recognized across the unconventional space. And it's a little bit lumpy as to when people recognize these in their reserves and they take them. But it's not all together without precedent. So we wanted to have a little bit of a conversation just on where the majority of these technical revisions lie. Again, steeper declines on wells drilled after 2017 as a result of tighter spacing in our non-op Eagle Ford. And there were a few spacing adjustments related to infill development as well. We feel very good about where the book lies today. And I think going forward, in terms of the cash-making capacity of this business, what's really important to these businesses, and that's better than it's ever been before. So a little bit disappointed in the reaction this morning. I understand, but I think it's a little bit of an overreaction to what is a non-cash accounting adjustment.

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

Thanks, Eric. Let's discuss some operational questions that have come up, particularly about Eagle Ford. The non-operated wells are showing results comparable to our operated program, but the capital costs for the Ranger wells are about 50% higher. Could you explain the reasons for these increased costs and also share some insights on the efficiencies we are observing in drilling and our goals to improve these efficiencies in 2024?

Eric Greager, President and CEO

Yes, great question. Just to clarify, the Karnes trough in Karnes County, Southwestern Duet, is one of the highest quality unconventional resources in North America. This resource was discovered in the mid to late 2000s and has been developed over time, showing very high quality but requiring a long development period, particularly with our non-operated Karnes trough assets. While the Karnes resource is exceptional, moving north and east into our Ranger lands shows a good quality reservoir, but it doesn't match the Karnes trough. The Karnes is the best resource in North America, while the reservoir in the Ranger lands can be described as Tier 2 plus or Tier B plus, indicating very high quality, but it requires more effort to achieve similar results. It demands additional energy and capital to fracture the resource adequately and generate the necessary surface area for well performance. This means strong well performance comes at a cost; we have to invest more capital and work harder. We are also using longer laterals to boost efficiency and achieve better results. Furthermore, we aspire to achieve 8% to 10% performance improvements in 2024 compared to 2023, building on operational enhancements made this year. These improvements revolve around aspects like bottom hole assembly designs and drilling efficiency. The choices in bit selection and the design intricacies of the BHA impact penetration rates and hole cleaning. Staying in the best rock is an intense and strategic effort, resulting in better overall performance. Our goal is to balance speed and cost management while ensuring we extract value from high-quality resources. We will maintain pressure to reduce capital expenditures, but we will only do so as we maximize performance from the reservoir. Since unconventional stimulation is a one-time effort, we need to ensure we execute it correctly the first time.

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

Okay, Eric, just continuing on the Eagle Ford, maybe a bit of a two-part question here. We have an investor asking about leasing programs or expanding acreage, sort of tuck-in bolt-on opportunities, what do we see in the Eagle Ford and maybe you could expand that even to Canada? And second part around the Eagle Ford would be would we even consider selling the non-operated Eagle Ford position?

Eric Greager, President and CEO

Yes. Let me start with the last point first. We have a strong position in the Eagle Ford, both in the non-operated and operated segments. Our team is effectively leveraging both aspects to enhance performance and operational efficiency. We are only six months in, and we’ve already achieved two consecutive top quartile quarters. I am very proud of the team, and there is much more ahead. Regarding the competitive and leasing landscape around our Eagle Ford assets, we are concentrating on small opportunities such as tuck-ins and working interest acquisitions, which are very efficient since they align with our existing development efforts. Acquiring interests in our own operated projects is particularly effective. These tuck-ins and extensions allow us to drill longer laterals, enhance efficiency, and optimize our gathering and processing capabilities. While you may not notice the impact of individual transactions, they contribute to cost structure improvement and better margins. In Canada, we have a strong team, particularly in heavy oil, with three land extensions and two discoveries that are performing well economically. We are excited about our progress, which includes three discoveries over the past three years along with land extensions for those findings. One notable discovery was Peavine, which was exceptional. We had a recent land extension, and there’s also Cold Lake, Waseca, and Mannville, along with the Rex at Morinville and Grizzly near Peace River, all of which are highly promising. We have the right team in place to capitalize on these opportunities. Lastly, in our Pembina Duvernay area, we are unlocking insights about that reservoir and there are ongoing opportunities around our current holdings that we plan to explore further, even if they may not be substantial enough to be considered material. Nevertheless, these initiatives definitely enhance the overall performance.

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

Your last question on the Eagle Ford relates to a technical difficulty.

Eric Greager, President and CEO

We continue to refine our list of candidates. Selecting sites in Canada is crucial for a refrac program. It's essential to identify candidates with the appropriate wellbore architecture, effective primary cementing, and good zonal isolation. The tubulars need to be sufficiently large to avoid complications with ultra slim hole technologies, which can be delicate for this kind of work. We have numerous candidates to consider. Additionally, it's important that these candidates originate from a time when they were under-stimulated. This refers to the days when orate and zirconate crosslinkers were commonly used, involving low volumes and tonnage, leaving significant resources untapped. To provide some perspective, our position began forming during the early development of the Eagle Ford, and many of these opportunities can now be revisited, assessed, and restimulated. For illustrative purposes, if we consider a section in the Eagle with 40 million barrels of oil equivalent, a full development program today in unconventional settings like the Eagle Ford might recover only 10% to 15% of the total resource. This means that from the original resource of 40 million BOE, only 4 million to 6 million BOE might be recovered, leaving 85% still in place. This is a critical time, coupled with the right pricing and economics, for refrac restimulations to retrieve some of that remaining value. In many ways, there are technologies that resemble the unconventional approach to enhanced oil recovery. There are numerous opportunities to continue unlocking this potential. We are currently conducting the necessary research and analysis to enhance our understanding. We have implemented refracs and have a comprehensive list of candidates that we are assessing and will be eager to discuss at the appropriate moment.

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

I do have one more question coming from the Eagle Ford and it relates to any constraints on completion activity. There is always, I think we are carrying index within the program at various points in time. But any constraints on the completion side of our business, Eric?

Eric Greager, President and CEO

We typically don't focus on building a document inventory as a standard practice. There isn't a deliberate effort to create one. We do have a working document inventory; for instance, when three rigs are operational, they will produce case and cemented wellbores at a rate that outpaces the crew's ability to clear them at the tailgate. This results in a working document inventory, but it will be addressed within a few quarters. This is mainly related to capital efficiency.

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

Perfect. Eric, I want to shift to a couple of other maybe more economic themes that have come through on the webcast as well here. Can you discuss M&A and views on being a buyer or seller at this part of the cycle?

Eric Greager, President and CEO

We've invested significant time and effort into our five-year plan, which outlines the entire cycle of our business. We are proud of it and expect to grow by approximately 2% annually from 2024 to 2028. By 2028, we aim to reach a production level of 170,000 BOE per day and reduce our debt to about $1 billion. Even at reasonable prices, we anticipate generating billions in free cash flow, a substantial portion of which will be returned to shareholders. In summary, over this five-year period, we expect 2% annual top-line growth. We also plan to repurchase 7% to 10% of our shares each year through our normal course issuer bid and will provide dividends. Overall, this reliable program should deliver a meaningful total shareholder return of around 10% per year, resulting in a well-capitalized, low-leverage business over time. This is our current focus.

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

A bit of a financial-related question, Eric, do we have any interest rate swaps on our floating rate debt? And if so, at what locked-in rate?

Eric Greager, President and CEO

We don't.

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

We don't talk a little bit about the capital structure.

Eric Greager, President and CEO

Yes, our capital structure is quite straightforward. We currently have two types of debt. The first is a high-yield senior unsecured debt due in 2027 amounting to $410 million, and the second is due in 2030, which totals $800 million. The 2030 debt has a coupon rate of 8.5%, while the 2027 debt has a coupon rate of 8.75%. Both are fixed-term debts and are well-structured, allowing us to manage them effectively. Additionally, we have some floating rate debt related to our credit facility, which is not subject to interest rate swaps or similar arrangements. It generally floats at SOFR plus 225 basis points, meaning it fluctuates slightly above SOFR. As benchmark interest rates change, this debt will adjust accordingly. Our primary strategy for debt repayment involves reducing the balance on our credit facility first.

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

Another sort of financial-related question around the entire business and free cash flow generation. But what would be our current breakeven price, Eric, and I'm thinking in WTI terms here?

Eric Greager, President and CEO

In WTI terms, I think about this at the asset level since we use individual asset breakevens for capital allocation. Initially, we focus on our lowest breakeven and highest performing asset package. We use breakevens to enhance our capital allocation efficiency. The breakeven numbers I'm considering range from the most defensive assets, which have breakevens in the 30s, to our least defensive assets with breakevens just under $60. So, notionally, it falls between the high 30s and high 50s, with mid-40s being the midpoint. The great thing is that these assets are categorized into Tier 1, Tier 2, and Tier 3, allowing us to maintain capital flow to selective tiers based on reservoir and asset quality. This flexibility enables us to capitalize on rising prices for upside and, when prices drop, to benefit from the defensive nature of the assets by reducing capital to those that have met a threshold of about 15% pretax IRR. We can do this using a well-established playbook. This approach illustrates how we thrive in varying price environments and supports our 60/100 collar structure.

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

Eric, can you comment on. And we've got time for I think, I'll give you maybe a couple questions here as we reach our limit. Can you comment on the Juniper position.

Eric Greager, President and CEO

Juniper had three escrow hold periods, each lasting about 90 days, starting with the gloves on June 20, 2023. After the first hold period ended, which was around September 18, they executed a trade for one third of their total shares, approximately 51 million shares. Currently, they hold about 12% of their shares, having transitioned from around 18%. As a result, they are classified as insiders, which prevents us from directly buying from them. The second escrow hold period concluded 90 days after the first, before Christmas 2023, and to our knowledge, Juniper has not sold any shares since then. There may be some adjustments in how these shares are categorized, but they still seem to own all of them and can choose when to sell. The third escrow hold period will expire in March, increasing the available shares for sale. Ultimately, Juniper will decide when to sell their shares, just like any other common shareholder.

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

Thanks, Eric. You've been very generous with your time here today. I do want to close. I had a number of comments and questions around the share price performance, both today and over a bit of a longer period of time. And so maybe you just reiterate your thoughts on the reaction today and maybe over a longer period of time. I mean you as a shareholder have been purchasing shares as well. What your comments as we wrap up.

Eric Greager, President and CEO

Yes. So I am not at all happy with the share price performance, but transformational deals like the Ranger merger acquisition create certain overhangs and those overhangs take time to work off. The Juniper ownership is, in fact, one of those and probably a pretty significant contributor to the overhang. There will be in March, a 102 million shares available. And Juniper may hold those shares forever, I just don't know, but they also might decide to sell them, and that creates a little bit of uncertainty around the shareholder community. Now in the first half of 2023, WTI languished a bit, kind of at an average WTI price of $75. And again, given the transformational nature of this transaction and its size relative to the legacy Baytex those prices weren't enough to create a great deal of excitement. But when prices rallied in the third quarter, we saw strong price performance, and that felt really good. It told us that there's a fundamental kind of understanding and some pent-up demand for the shares when prices do rally. I personally believe in the stock, I believe in the company, I believe in the teams. And I think we're demonstrating where it really counts at the cash level, at the cash cost level, at the cash-making or generative capacity at the business level that this is a great business. And to believe in the business, believe in the teams, believe in the assets and the strategy. And I think the overhang will lift. The CRA matter didn't help. It just added a little bit of additional uncertainty. It didn't help. But we will continue delivering on our five-year plan, delivering quarter-over-quarter. And I believe we are still a great value, and this is a great entry point in a very high-quality company.

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

Okay. Thanks, Eric. Well said. And I do think we are at our time limit for this call today. So thank you, Galen, and thank you to everyone for participating in our year-end conference call. Have a great day.

Operator, Conference Operator

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