Baytex Energy Corp. (NYSE:BTE) Q4 2023 Earnings Call Transcript

Baytex Energy Corp. (NYSE:BTE) Q4 2023 Earnings Call Transcript February 29, 2024

Baytex Energy Corp. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp. Fourth Quarter and Full-Year 2023 Financial and Operating Results Conference Call. As a reminder, all participants are in listen-only mode and the conference is being recorded. [Operator Instructions]. I would now like to turn the conference over to Brian Ector, Senior Vice President, Capital Markets and Investor Relations. Please go ahead.

Brian Ector: 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: 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 average 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 nonoperated 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 onstream 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 nonoperated 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 producer, 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.

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Q&A Session

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

Unidentified Analyst: Hi, good morning. This is [indiscernible] 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: Hey, Rob. Thanks for the question. You’ll hear us continue to stay 12,000 to 15,000. But honestly, I think it’s going to hug the high end of that. So probably over time, maybe just referring to around 15,000 as a plateau rate. I think that makes a lot of sense. But there’s — we’ll continue to have this conversation. As the wells come on and help us understand performance, we’ll inform that conversation accordingly. But so far, it has outperformed our expectations. So I would say hug the high end of that and more to come.

Unidentified 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: 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: Yes, great. Thank you. That’s really helpful. I will turn it back.

Eric Greager: Thank you, Rob.

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

Philip Skolnick: 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: Yes. You’re right, Phil, and thanks for the question. So Q1, I would anticipate probably in the bottom of our 150 to 156 range. So think kind of 150, which is where we’ve been discussing it in the budget conversation. And then if it’s kind of 150 to 151 in that range as we turned out our budget, then make a small adjustment. I mentioned 2,000 BOE a day. Full-year is going to be right in line with the midpoint of our range. But we could be a little bit below what we talked about in the budget conversation. So I think it could be 149, 149.5 something like that as we work to overcome the production disruptions in — as a result of the polar vortex. You’re right. We actually have seen — because we’ve seen such strong well performance out of our Eagle Ford, that well performance includes all phases, right?

It includes natural gas, oil and NGLs. And the well performance has been, as I mentioned in my prepared remarks, top quartile that has also brought on a fair amount of gas. And that gas has been resulted in probably a 1% or so change to our total liquids gas mix in Q4. But I would anticipate moving into Q1 that we’re going to shift back into more balance with regard to our historical trends. So think kind of 84, possibly or right around there in terms of the liquids mix to gas. So things will trend back towards, I think a more balanced trend line.

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

Eric Greager: 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: Perfect, thank you.

Eric Greager: Thank you, Phil.

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: All right. Thanks, Galey. 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 off-line. 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: Yes, it’s a great question, Brian. And I appreciate the question through the web portal. These are — this is not a perfect science, and we continue to engage with our shareholder community and our Board, and these are — these are really interesting and intellectually stimulating conversations because, again, it’s trade-offs and it’s subjective. But we really do like the 50-50 framework. So 50% of the free cash flow generated goes to our debt. And if you think about the debt as a return on those on that marginal free cash flow dollar that is committed to that, if you think about the return on that. On an after-tax basis, that’s for round numbers, let’s call it 6%. So an after-tax return of 6% when you commit a marginal free cash flow dollar to the debt pay down, and you compare that to, if I’m doing back of the envelope math today, about a 16% free cash flow yield.

And if you use that as a proxy measure for the return on a marginal free cash flow dollar applied to paying down equity or buying back shares. There are just two pools of capital and they have different underlying cost of capital associated with them. If you were buying a car or building a home or financing your business and you had one pool of capital that cost you 16% and one pool of capital that costs you 6%, then you would generally want to lean toward paying down the 16% of the higher cost pool first. And that generally guides this vision, but because there are also underlying dynamics between enterprise value, market cap and the debt component of enterprise value and how it shifts from EV as you pay down debt over to market cap, there are some underlying incentives to keep that allocation more balanced than a 16 to 6 would imply.

And so — based on all of this, what we’ve said is, look, you can’t make a perfect formulaic answer. We like 50-50 because it recognizes the value of both sides of that. And the bonds actually trade really well. Last I looked, the bonds were trading at $104. So it’s a really strong signal that the credit profile and credit worthiness and the debt is strong. And that also tends to tell us that continuing to push capital, free cash flow into our equity buyback is probably a really good place to focus. And so let me just pause with that, Brian. And happy to dig in a little bit more if there are other questions that need more but that is well parked.

Brian Ector: Okay, thanks Eric. Another common theme coming through on the questions does relate to the noncash impairment that [indiscernible]. So a number of investors asking for maybe just a little bit more of an explanation behind the impairment on the nonoperated Eagle Ford and the retained Viking assets. Can you elaborate a little bit for people little bit of comfort with what we’re doing, please?

Eric Greager: 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 President. 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: Okay. Thanks, Eric. Let’s shift a little bit to the — to some operational questions that are now coming in as well. And here’s one related to the Eagle Ford. As talking about the non-operated wells having similar results to our operative program, but the capital on the Ranger wells is higher, it’s about 50% higher. What are the reasons, Eric for the higher well costs and — at the same time, I think maybe you can speak to some of the efficiencies we’re seeing from a drilling standpoint and our target to improve the efficiencies in 2024?

Eric Greager: Yes. Great question. So — just to be clear, the Karnes trough, this is Karnes County, Southwestern Duet in that general area is I think, objectively, some of the very highest quality unconventional resource in North America, just very, very good resource, discovered in the mid-2000s, late 2000s and has been kind of held and locked up and developed over time, very, very high-quality resource, long in its development as we have recognized with our non-operated Karnes trough assets. Very good quality, but having been kind of developed over a lengthy period of time. As you move up to the north and east into the block of our Ranger lands, the concentrated contiguous block of our Ranger lands, the reservoir quality is good, but not as good as the Karnes trough.

And so there’s exceptional resource quality, the best in North America, that’s the Karnes. And then there’s one step down, I would call it, Tier 2 plus or Tier B plus, very high-quality resource. But in order to get the results to punch at the same level, you’ve got to work harder. You’ve got to spend more energy, intensity, hydraulic intensity, kinetic energy to shatter the resource in the reservoir and generate the fracture surface area necessary to liberate in slightly lower quality resource. And it’s this fracture surface area, that generates the well performance that we’re seeing, but it takes more effort and it takes more capital. And as a consequence of that, we’re seeing very strong well performance, but we’ve got to work harder and we’ve got to spend a bit more capital.

These are also longer laterals, as I mentioned in my prepared remarks. And so we’re building efficiency in by drilling longer laterals and getting strong performance out of those longer laterals. And I think one other point that I’ll just try to tuck in here is, we continue to target 8% to 10% performance improvements in 2024 over 2023, and there were embedded improvements in 2023 as well. These are operational improvements, but they really orbit around things like BHA designs. So the bottom hole assembly and drilling the design of that BHA, the efficiency, the bit selection. These are multi-blade polycrystal and diamond bits and the way the cutters are designed, the way the bits are designed, the way the BHA is designed, affects the penetration rate, hole cleaning.

The way we stay in zone is — it’s a very energy and intellectually intensive effort to stay in the best rock, but it results in kind of active geo steering to stay in the best rock, but results in better ultimate performance. And so you want to get faster, but you also want to stay in the highest quality resource. And it’s always a balance between getting faster, pushing down costs while also staying in the highest quality resource and getting the biggest bang for the effort. And so that’s the balance. But we will continue to put a lot of downward pressure on those capital numbers, but only to the extent that we continue to drive maximum performance out of the reservoir because you kind of get one shot at unconventional stimulation and you want to make sure it’s right the first time.

Brian Ector: 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: Yes. We — so let me just take the last one first. We really like our Eagle Ford position, all of it. The non-op Eagle Ford, the operated Eagle Ford, the team in place today is getting the best out of both and putting them together in ways that elevate the combination. And so — we’re going to continue to realize both operational efficiencies and improvements and performance efficiencies and improvements over time. We’re just six months in, and we put two back-to-back top quartile quarters in place. I couldn’t be more proud of the team, and there’s a lot more to come. In terms of the competitive and leasing landscape around our lands in the Eagle Ford, there are a lot of small opportunities, we’re focused on small opportunities, tuck-ins, working interest acquisitions because they’re very efficient.

You’re already investing the effort in developing. And if you can buy working interest in your own operated program, that’s real efficient. So tuck-ins, working interest extensions, those allow us to drill longer laterals, be more efficient, take advantage of the capacity of our gathering and processing apparatus. So all of that’s very efficient. And you won’t see any of it, because no single transaction ever rises to the level of materiality, but we continue to work on efficiency and it hits the cost structure, improves the margins. In Canada, we talk openly about how strong our teams are, and in particular, around heavy oil. We’ve got three land extensions, two discoveries and continue to make good on the economic performance of those land extensions and discoveries.

There will continue to be more to talk about there. I’d like to say three discoveries in three years and three land extensions on those discoveries. One was Peavine, it was spectacular. We had a land extension recently. Of course, Cold Lake, Waseca, and the Mannville, we just talked about. The Rex at Morinville, which is a clear water equivalent just north of Edmonton. And then, of course, the Grizzly near Peace River, the blue sky. And these are all highly prospective, and we’ve got the right team at the right time to take advantage of those opportunities. And then finally, I would say, within our Pembina Duvernay, we continue to unlock the secrets of that reservoir and there are opportunities in and around our current position where we will continue to look and possibly take advantage of.

Again, they may not be large enough to ever hit materiality. So you may not know, but these things definitely improve the performance of the overall apparatus.

Brian Ector: Your last question on the Eagle Ford. Relates [Technical Difficulty].

Eric Greager: We actually do. So we continue to high grade our candidate list. Canada selection is probably the most important part of a refrac program. You’ve got to find candidates that have the right wellbore architecture, that have the right degree of primary cementing and zonal isolation. Tubulars that are large enough to be able to get in and out of without getting into ultra slim hole technologies that become a bit fragile for this kind of work. And we have a long list of candidates. The other thing that’s important is the candidates have to date back to a vintage or a time when they were let’s call it, under stimulated. These are the days back in the day when orate and zirconate crosslinkers were the thing and the very low volumes and low tonnage and leaving a lot of resource in the ground.

To put it in just kind of scale context. Our position began developing in the early stages of the Eagle Ford development and many of those opportunities can now be reentered and reevaluated and restimulated. If for the sake of just illustration, let’s say there are 40 million barrels of oil equivalent in a section in Eagle, just a representative number to put it in terms of scale. A full development program today in an unconventional like the Eagle Ford may recover 10% to 15% of the total resource in place. So 4 million to 6 million BOE of a 40 million BOE original resource in place number, that leaves 85% of the original resource still in place. And this is a time and a place and an opportunity at the right pricing and economics for refrac restimulations to extract some of that value that’s left in the resource.

And in some ways, other technologies that feel — that look and feel like the unconventional version of EOR. And so lots of opportunities to continue to unlock in this. We’re doing the science, the math and the physics today to better understand it. But we do have refracs in the ground and a long candidate list that we are currently evaluating and we’ll be excited to talk about at the right time.

Brian Ector: 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: Yes, we generally don’t build just as a matter of practice. We don’t build a doc inventory per se. So it’s not an intentional effort to sort of build a doc inventory. We have a working doc inventory, so when — for example, three rigs are running, they will be generating case and cemented well bores faster than the crew will be clearing them at the tail gate. And so you build a working doc inventory, but it will be cleared within a few quarters. And that’s really just a capital efficiency piece.

Brian Ector: 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: Yes, what I can say is we’ve really like our five year plan. We took a lot of time and a lot of effort to put together. Our LRP which runs through the entire fold appellation cycle of our business. But we published our five-year plan. We’re very pleased with it. We grow from 2024 to 2028 at notionally about 2% per year. And by 2028 we’re 170,000 BOE a day business. We paid down our debt to about a $1 billion notionally at that point in 2028. And turn by turn even at reasonably — price is reasonable by today’s standards, so kind of close to support levels, we’re generating billions of dollars of free cash flow and billions of dollars of that free cash flow will be returned to shareholders as well. So — at the top line, over that five-year program, we’re generating 2% per year top-line growth.

We’re taking, let’s call it, 7% to 10% per year of our shares out through our NCIB. And we are generating a dividend as well. And so the total shareholder return associated with that very straightforward and reliable program over five years is meaningful, probably 10% per year on a TSR basis, and it results in a strong well-capitalized, low leverage business over time. That’s what we’re focused on today. And I think I’ll just park that one there.