Baytex Energy Corp. (BTE) Q1 2023 Earnings Report, Transcript and Summary

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. [Operator Instructions] The conference is being recorded. [Operator Instructions] 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 increase 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 2 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 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 -- 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 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.

[Operator Instructions] Our first question comes from Amir Arif of ATB Capital.

Just a couple of quick questions. Just on the hedges, I noticed you did add another -- quite a bit of oil batches you went from, I think, like 10,000 to 15,000 barrels a day. I know you were looking to increase your hedges heading into this -- closing this transaction. What's the target range on the hedging in terms of how much volumes you're looking to hedge post 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 NRI production. So net production -- net oil production up to 40%. And 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 head 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 noway hedges in as we see fit. But yes, again, looking kind of to the absolute $60 floor, and then kind of getting a 5 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. And just second question, just on the guidance. I know pro forma guidance -- guidance on the combined company won't be out until after the deal closes. But just curious, we've seen some companies who require assets where to slow down the pace of activity and use that as a free cash flow engine, others view it as a noncore -- or asset that's been undercapitalized and accelerated capital, I mean the Ranger it's a pure-play preferred producer, just direct [indiscernible] what you're thinking of pace of capital relative to where Ranger was without capital program?

Yes. Thanks, Amir. So we're thinking -- we slow it down a little bit, and the reason for that is to be pretty consistent with the balance of our portfolio and our organic production growth rate generally pointing toward about 4% per year organic production growth. Ranger was growing at faster than that. And we like this plan for a couple of reasons. One, it allows us to take the team's talent and resources and efforts and time and focus a little bit more on kind of deeper technical insights working the assets technically and operationally around just operating efficiency and not growing at quite so fast. So we're thinking -- 2 rigs level loaded, maybe a little bit more than 2 rigs. So there might be a spot rig that comes in from time to time. But generally speaking, we're going to hold the asset to a slight inclined, but not growing as fast as Ranger Stand-Alone had it growing. Again, that's going to liberate resources, time and energy and gifts and talent to focus on squeezing out costs, improving operational efficiencies. We also think, generally speaking, level loading assets across the portfolio is the best way to extract operational efficiency and synergies out of the assets. And so it's not unique to Eagle Ford that will level load -- we level load the balance of our operations as well, targeting this kind of level-loaded nodes or channels of efficiency where the asset works really well, and the capital efficiencies are optimized. So that's our plan, slow it down just a little bit, and that will allow a number of things kind of naturally fall in place in there.

That's great color, Eric. And then just 1 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 been -- we've drilled 3 different laterals. We better understand in these areas now 2 pads, 3 -- 3 laterals each of 3 wells each better understand 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. Like 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 nothing 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 and in Q1, and we produced 26,000 BOE a day. So that’s not nothing. 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 so – 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 a 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 is 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?

Great. Thanks, Brian. And this stems to the question from the call earlier. So I'm going to anchor to $70 -- notionally, that's where we sit today. Basically, at $70, we are generating an 80% rate of return about a 3x recycle ratio and 16-month payout. And then if I just think about that high level for flexing it up and down based on oil prices, for every $10 move that West Texas makes, it's about a 30% adjustment on rate of return, up and down, 0.5 turn on recycle ratio and plus/minus 4 months on the payout. I think the bigger picture is just how does that fit into the overall construct of the portfolio. No doubt, Peavine would be the highest rate of returns that we ultimately generate followed by Eagle Ford and Lloydminster, our heavy-oil -- cold flow fairway. The Duvernay slots in quite nicely below that. And then when you extrapolate that 1 step further, just thinking about the grander unconventional resource construct that it's very attractive and competitive rates of return when you look really 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?

Yes. Thanks, Brian. I appreciate the question. I think there are both incremental and meaningful opportunities. And I think this really kind of speaks to the comment I made earlier, but I'll take it maybe a little bit deeper. When pure-play companies like Ranger and others I've been involved in. When you're moving fast, it's important with smaller scale to stay very, very lean. And when you're moving fast and you're growing the business, you focus on continued execution of the growth program and the growth profile. We're, as I mentioned earlier, stepping back just a little bit, slowing down the pace of growth to fall kind of in line with our low to mid-single digits. And I'll just say as a single number, kind of point to 4% per year organic production growth. And at that pace, it's a little over 2 rigs level loaded throughout the year to get that done. This slowing the pace down a little bit, bringing broader resources from our Canadian enterprise, both in and around Duvernay and also resources that we've been exploring along the way, and combining those with the substantial and impressive performance that Ranger has brought forward in the last couple of years, just since the new management team has been in charge of the assets, that was late '20, and of course, increasing new management through '21 and '22. They have made a substantial improvement in performance. We think there's more that can be done. We think this is at a number of levels. Sometimes, there's a little bit more active geosteering that can take place to reside or live with every foot of the wellbore and the highest quality reservoir. And that's something that can and will be explored using obviously, real-time wild drilling data collection to ensure that we remain in the highest quality reservoir. The team has done a really good job. But again, when you're moving really fast, sometimes there are opportunities that get missed. Stimulation design, I think there are things we can do to step up the intensity. Again, the team has extracted a great deal of quality, value accretion and performance out of the assets, but we think there is a little bit more that can be done with regard to applied math and science in and around those assets, involving machine learning capabilities, and we're really eager to put our heads together with the technical team at Ranger and the subsurface and the technical team here. And I've got some frameworks in my own mind that we want to explore and combine. So I'm impressed with what the team has done so far just in the last couple of years, and they have really demonstrated that these assets can punch above their weight in terms of what the world had come to expect prior to 2020. But I do think there are incremental opportunities to continue that trajectory. And I think for the sake of just having something to stare at, I do want to point to 1 slide in our Baytex plus Ranger deck that actually helps to put kind of words to data, and I'm going to stare at Slide 9 for just a minute here, and I won't belabor the slide, but I just want to point the audience to this slide because this in the upper right shows year-over-year performance improvement. And you can see in the lower left, how much better the 2023 wells to date are than '22, and -- those are incrementally better than '21 and so on. And then on the lower left, measured against the best operators in the area. You can see that, that performance is strong and getting stronger with time as you see that 24-month period closing in on the top column. And so I think it goes beyond just drilling and stimulation though. There are nuances around PVT and the unique characteristics of pressure, volume, temperature and the petroleum fluids and how they behave, as they flow through the reservoir, through the frac pack, through the wellbore and to the surface. And we're going to employ sophisticated nodal analysis to ensure and sophisticated PVT to ensure that our reservoir pressure drawdown and management is pulling as much oil value into the curve and forward as possible. And there are certain best practices to ensure that, that gets done. And again, by slowing down a touch, we're able to focus the very talented team in Ranger on some of these more detailed technical and analytical pieces. So thank you for that.

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. And 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 kind of ties into maybe the free cash flow and free cash flow allocation question. But do you believe the current share value reflects our future growth expectations? What will be done to enhance the value of the share price more consistent with that -- with your expectations for the business?

Yes. So implied in the second part of that question is no, I don't think our current share price reflects the value I see in this business. I think we're pretty deeply undervalued. And that is exciting for me because it creates a lot of opportunity for those of us sitting on this call. The way we're going to unlock that potential is through blocking and tackling in the business, finding more in bill, because oil is where oil was in this business sits on 1.7 million net acres of HBP lands. I promise you there's more of that to come. I can simply tell you; we've been engaged in an organic exploration program across all of our lands. And Morinville, is 1 bite of a pretty steady diet. So that's 1 thing. The other part of this that I think is really important is return of capital to shareholders will continue to take up and cancel shares. As we did last year and as we will do increasingly, as this business grows in scale and grows in free cash flow on a per share basis, we'll be able to allocate both more of the absolute free cash flow, and it's a bigger number. And on a per share basis, we'll be able to allocate more of that buyback and cancel those shares. And so there's that natural if you like, upward pressure on all the per share metrics that will make its way through to the share price. And it will take some time for that to happen. But as that happens, there will also be natural appreciation in the share price. And that natural appreciation in the share price just through good execution, blocking and tackling and discovery of assets productive, high-quality profitable assets within our current franchise will add a great deal of sort of real value along the way. And if the share price appreciation doesn't close in on our intrinsic value as it should, that just tells me that there are inefficiencies in the marketplace. That will result in a discount between our intrinsic value and our share price, and we'll buy that discount using our free cash flow generation to do so. I couldn't be more excited about the business. It just had a great deal of capability today. And one of the things about the oil and gas industry globally today, but especially in North America, is the inefficiency is creating opportunities where assets are mispriced -- and materially mispriced. We're one of them, and we're going to take advantage of it by buying back 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 -- to the quarterly conference call. Eric, are there any meaningful noncore 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. So I'm going to try to answer the first one, and then I'll pitch the second one to Chad Lundberg. We -- the way we've been thinking about our portfolio, and I'm going to stare out a different slide within our rollout deck because this is one that has been really handy to use in the conversation around our portfolio. And I'm staring at Slide 10. Again, I'm in the Baytex plus Ranger deck if you're in front of your computer. And I like to look at this starting in the lower left panel, which is our portfolio run at $75 WTI. So you'll notice in the footnotes, it's what I described earlier as our benchmark price. And you look at the y-axis, you see Peavine Clearwater, it's spectacular. And you see our Karnes acreage that's the Eagle Ford in orange. And then you see in blue, this is the Ranger Eagle Ford lands. And then as these trails off to the right, the way to think about the portfolio is -- it probably won't be whole asset. So don't think Duvernay as a whole asset or Viking as a whole asset or Lloyd as a whole asset. But think about these areas or Peace River as -- or Eagle Ford as a whole asset. Think about taking each of these assets and disassembling them into packages of -- or tier -- reservoir tier areas, Tier 1, Tier 2, Tier 3. And then think about how kind of Tier 3 assets would perform in a portfolio. They're -- because we're always going to be creaming allocating our capital resources to the highest returns within our portfolio to the extent that those assets can accept -- efficiently accept more capital, and I can expand on that, too. But to the extent that they can efficiently accept more capital and process that capital, we will continue to put capital to the highest returning assets. But what that means is if you maintain this 4% per year production growth, maintain this kind of 50% reinvestment rate, which generates a great deal of free cash flow for all the things we talked about earlier. Then it also implies that there are going to be assets within this portfolio that cannot compete for capital. And in a discounted cash flow world, those assets might be out 6, 8 years, 10 years. And in our portfolio, they might not compete. But in someone else's portfolio, they might. And if they can command capital funding on year 1 or year 2 in someone else's portfolio and year 8 or year 10 in our portfolio, then it's clearly better for our shareholders, and they're worth more to us if we sell them than if we keep them. And that's the way we're thinking about it. It's a very systematic corporate development, portfolio management and optimization strategy. And we actually had that work underway, which is why the skyline plots were so readily available. But we've disrupted it by adding this major asset in the Eagle Ford. And so we wanted to reevaluate. But that's the way we're thinking about it. But rather than talk about specific assets, I just wanted to take it maybe a level deeper and suggest that it's probably going to be parts of major assets as opposed to whole major assets. That's a great question, though. Thank you.

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 basis 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 going to 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 -- of consideration in terms of capital markets 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?

Yes. So it has been encouraging to see the WCS-WTI basis differential compress, it has come in some in the last couple of months and even quarter. Q1 actually didn't show it because it's -- some of what was happening was after the formal closing or end of the formal calendar Q1. We anticipate Q2 is going to have a substantially lower basis dip shown in all the numbers. And you'll see this in all of our peers who publish data on Q1 with WCS exposure. TMX is going to help. There's just no question about that. When you add inch miles of egress to a producing region like WCSB, there's just no question that's going to help. We don't have -- we are not an anchor tenant. We don't have firm transport on TMX. But because the egress is increasing out of the basin, we think WCS-WTI is probably heading toward the pipeline economics defined by the mainline to the Gulf Coast. And so pipe economics to the Gulf Coast are in the $10 to $12 range. We think that's probably the equilibrium price over time. There will be opportunities where it dips lower for reasons that are unique in time and location. We'll try to capture those. But we're definitely watching the marketplace, watching TMX progress, watching line fill, expect and understand that to be taking place in Q4. And then TMX, best we understand it, should be flowing in Q1, Q2. So this kind of defines the way we're thinking about it, but we do think it's headed toward pipe economics to the Gulf Coast. And that should define 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.