Baytex Energy Corp

TSX:BTE

Earnings Call Analysis

Q3 Performance Aligns with Expectations, Synergies Achieved

The company's third-quarter performance aligned with expectations, including successful drilling operations with two high-performing rigs, signifying a highly operationally efficient period. During the earnings call, executives highlighted strategic refracs and exploratory wells in Western Canada as ongoing initiatives that could potentially yield higher range outcomes. Cost savings from the merger of Baytex and Ranger were discussed, focusing on modest but fully achieved synergy targets. Continuous improvement in operational efficiency is anticipated. ESG efforts, particularly lowering freshwater intensity in operations, are being implemented using wastewater for fracture stimulations. Lastly, the breakeven oil pricing for the company's entire portfolio was mentioned to be in the low to mid-40s per barrel.

Eagle Ford Operations Reflect Positive Developments

During the earnings call, Eric Greager, an executive at the company, confirmed that the results from the Eagle Ford operated acreage are aligned with their expectations. The discussion highlighted the planning of refracs, a method that shows innovative approaches to increase hydrocarbon recovery from existing wells. Greager emphasized the extensive groundwork in designing and setting performance expectations, delineating an efficient operation supported by top-performing rigs and consistent clearances of DUC (Drilled but Uncompleted) inventories.

Exploratory Efforts in Western Canada Show Promise

The company's exploratory wells in two new areas in Western Canada are showing a potential range of 30 to 100 locations each, as per Greager's response to an executive's query. With ongoing development in Q3, more insight is expected in the fourth quarter. These efforts illustrate the company's strategic expansion in areas that may supplement its production platform significantly.

Synergy Gains from Baytex-Ranger Merger

Greager addressed the progress made in terms of synergy savings following the merger between Baytex and Ranger. While the initial expectations for cost savings were modest, the company has achieved these goals by streamlining operations and eradicating redundancies in various back-office aspects. Greager anticipates additional gains to manifest as operational efficiencies over time.

Commitment to Environmental, Social, and Governance (ESG)

A shareholder's query redirected the discussion towards the company's engagement with ESG-focused initiatives, specifically regarding wastewater treatment technologies. Greager outlined the company's efforts to reduce freshwater intensity in operations, utilizing municipal and effluent water for hydraulic fracturing. This initiative highlights the company's awareness and proactive measures in addressing freshwater use, underlining its ESG commitments.

Oil Pricing Breakeven and Operational Efficiencies

The company has aimed to lower the breakeven point for oil pricing, with Greager indicating a range in the low to mid-$40s across the entire portfolio. The ongoing pursuit of capital and operating expense efficiencies is expected to further reduce this threshold.

Addressing Share Price and Investor Confidence

Greager responded to shareholders' concerns regarding the share price performance, recognizing frustration over the lack of traction despite buybacks. With Q3 being the first full quarter after the Baytex-Ranger merger, the company sees this as an opportunity to prove its asset quality and the capabilities of its team. Greager looks forward to continued strong performance and is hopeful that upcoming quarters and year-end results will foster greater confidence in the company's valuation.

Earnings Call Transcript 2023-Q3

[Operator]

thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Third 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, Senior Vice President, Capital Markets and Investor Relations. Please go ahead.

[Brian Ector, executive]

Thank you, Ariel. Good morning, ladies and gentlemen, and thank you for joining us to discuss our third quarter 2023 financial and operating results. Today, I'm joined by Eric Greager, our President and Chief Executive Officer; Chad Kalmakoff, our Chief Financial Officer; and Chad Lundberg, our Chief Operating Officer. While listening, please keep in mind that some of our remarks will contain forward-looking statements within the meaning of applicable securities laws. I refer you to the advisories regarding forward-looking statements, oil and gas information and non-GAAP financial and capital management measures in yesterday's press release.

All dollar amounts referenced in our remarks are in Canadian dollars unless otherwise specified. 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 will now turn the call over to Eric.

[Eric Greager, executive]

Thanks, Brian. Good morning, everyone, and welcome to our third quarter conference call. For Baytex, this represents the first full quarter of combined operations following the Ranger acquisition and demonstrates the strength of our diversified North American oil-related portfolio. The integration has progressed extremely well, and we have delivered strong results from Western Canada and the Eagle Ford in Texas. During the third quarter, we delivered top quartile results from our operated Eagle Ford assets, continued exceptional Clearwater results at Peavine where we now hold the top 30 wells drilled across the entire Clearwater Fairway and significantly progressed our Pembina Duvernay play with 6 wells drilled and completed, trouble-free earlier this year which are all tracking to our type curve performance expectations. I'll elaborate on this well performance in a few minutes.

I'm also excited to announce 2 new land extensions at Peavine and Cold Lake as we continue to leverage our heavy oil expertise and recent exploration successes. We continue to execute on our 2023 plan and now anticipate fourth quarter production of 158,000 to 160,000 BOE per day, 84% weighted to oil and NGLs. We are forecasting full year 2023 exploration and production expenditures of just over $1 billion, which is consistent with our previous guidance.

Based on the forward strip for the balance of 2023, we expect to generate free cash flow of approximately $400 million during the fourth quarter and $650 million for full year 2023. As a reminder, we increased our direct shareholder return to 50% of free cash flow on closing the Ranger acquisition, which has allowed us to increase the value of our share buyback program and introduce a dividend. The remainder of our free cash flow continues to be allocated to the balance sheet.

Our normal course issuer bid allows us for the purchase of up to 68.4 million common shares during the 12-month period ending June 28, 2024, and as a result of our free cash flow profile, we have increased the pace of our share buyback program during the fourth quarter. Through October 31, 2023, we repurchased 28.1 million shares for $155 million, representing 3.3% of our shares outstanding at an average price of $5.51 per share. In addition, we paid an initial quarterly cash dividend of $0.0225 per share on October 2, 2023, and our Board has declared our Q4 cash dividend of $0.0225 per share to be paid on January 2, 2024. I'll now shift to our Q3 results.

Production during the quarter was 150,600 BOE per day, and we delivered adjusted funds flow of $582 million, $0.68 per basic share. We generated free cash flow of $158 million, $0.19 per basic share. Exploration and development expenditures totaled $409 million during the quarter consistent with our full year plan, and we brought 87.8 net wells onstream. As of September 30, 2023, our total debt was $2.7 billion, representing a total debt-to-EBITDA ratio Q3 '23 annualized of 1.1x.

During the third quarter, we repaid our USD 150 million term loan. Our total debt at quarter end increased relative to Q2 '23 due to the impact of the strengthening U.S. dollar relative to the Canadian dollar and our U.S. dollar-denominated debt, along with working capital adjustments. Based on current commodity prices and forecast free cash flow for the fourth quarter, we expect to exit 2023 with total debt of approximately $2.5 billion. I'm going to shift now and talk more about our recent activity.

In the Eagle Ford, our Q3 program reflects strong results across the black oil and condensate thermal maturity windows of the Lower Eagle Ford. Our operated assets, the 13 wells generated an average 30-day initial production rate of 1,500 BOEs per day, 78% oil and NGLs per well, ranging from 769 BOEs per day to 2,355 BOEs per day. 7 wells from 3 pads. These pads are the Bloodstone, the Bubinga and the Hickory generated an average 30-day initial production rate of 2,000 BOE per day, 65% oil and NGLs per well. When we compare these results to a data set of 784 wells sourced from public data, our Q3 performance ranks in the top quartile of all wells drilled in 2023 in the Eagle Ford, and on a production per lateral foot basis, we are solidly in the second quartile. So I'm very pleased with this performance.

In addition to delivering strong results, we remain focused on base optimization and continued drilling and completion performance. Our Pembina Duvernay light oil assets are in the demonstration stage of commerciality and offer high operating netbacks with strong economics and the potential for significant organic growth. We brought 6 wells onstream mid-summer. The 6 wells generated average production rates of approximately 950 BOE per day, 89% oil and NGLs. In September, ranging from 790 BOE per day to 1,080 BOE per day and continue to track to type curve performance expectations. Production from the Pembina Duvernay increased to over 7,500 BOE per day in September, up from 2,000 BOE per day in H1 2023, and the 2023 program has significantly advanced our understanding of the reservoir as we continue to progress this light oil resource play. On the heavy oil side, following a relatively quiet second quarter due to spring breakup, our program ramped up during the third quarter with 28 net heavy oil wells onstream, 14 at Peavine, 8 at Lloydminster and 3 at Peace River.

At Peavine the 14 wells generated an average 30-day initial production rate of 725 barrels per day per well, ranging from 330 barrels per day to 1,073 barrels per day. Production at Peavine averaged almost 14,000 barrels per day in Q3 '23, up 69% from Q3 '22 and increased to 16,400 barrels per day during the month of September. We are also following up our recent heavy oil exploration success at Morinville, Alberta and Cold Lake, Alberta during the fourth quarter. Building on our heavy oil expertise, we have expanded our heavy oil development fairway through 2 land extensions, including a 10 section extension at the Peavine Métis settlement adjacent to our existing 80 section land position at Peavine and to farm-in on 17.75 sections of land perspective for Mannville development near Cold Lake in Northeast Alberta. We've included a map of these incremental land positions in our updated Investor Relations presentation.

Shifting to risk management. We employ a disciplined hedging program to help mitigate the volatility in revenue due to changes in commodity prices. For the first half of '24, we have entered into hedges on approximately 40% of our net crude oil exposure, utilizing 2-way collars with a floor price of USD 60 per barrel and a ceiling price of USD 100 per barrel. For the second half of 2024, we have entered into hedges on approximately 25% of our net crude oil exposure, utilizing 2-way collars with a floor price of USD 60 per barrel and a ceiling price of USD 98 per barrel. As I wrap up my prepared remarks, I would like to reiterate our commitment to operational excellence and delivering long-term value and enhance shareholder returns. I'm very pleased with the operating results across our portfolio, which has set the stage for a strong finish to 2023. We do see our shares as undervalued, and we have stepped up our share buyback program during the fourth quarter. We're a strong North American energy company with a high-quality, diversified oil-weighted portfolio across Western Canada and the Texas Gulf Coast.

And now operator, we are ready to open the call for questions.

[Operator]

[Operator Instructions] Our first question comes from Greg Pardy of RBC Capital Markets.

[Greg Pardy, analyst]

Eric, I know it's still early, but what are your broad strokes, I think, in terms of spending any guidance maybe around production so forth for 2024?

[Eric Greager, executive]

Yes, it's a good question, Greg. Thank you. We like to think about 2024 as an extension of the second half of 2023. So if you were to take H2 capital on a half year basis and extend that out into 2024 and the range of 155,000 to 160,000 BOE a day and extend that across 2024, there'll be a little bit of lumpiness seasonally. But I think that would be a really good way to think about 2024.

[Greg Pardy, analyst]

And then I'm going to shift gears on you. Production rates, like you've done the land extension now in the Clearwater. So good on getting that done does any of this really change that 12,000 to 15,000 barrels a day range that you've been kind of guiding us towards where you think you could stabilize production in the Clearwater or does that...

[Eric Greager, executive]

That's a great question. We are pushing kind of the top of that range here in Q3 and continue to see encouraging results as we develop across the body of what now looks like a green headed prairie chicken on our map. And so I do expect, Greg, that the 12,000 to 15,000 barrels a day is probably something we'll continue to say, but I would expect to live near the high end of that more often than I might have expected even 6 months ago. So it is a good, strong development plan over time.

We continue to want to be very disciplined and really thoughtful about how we march forward. Social license to operate is very important to us and maintaining a strong and transparent relationship with the communities in which we operate, including here the Peavine Métis settlement, it's very important to us. So I'll reiterate the 12,000 to 15,000 barrels a day, and I'll probably follow that up by saying we could live at the high end of that consistently, but you'll probably hear us keep saying that.

[Operator]

Our next question comes from Menno Hulshof of TD Securities.

[Menno Hulshof, analyst]

I'll start with a question on Lloydminster Mannville since you farmed in on another rough number 17 sections. You have a lot of running room in the play. And I'm just looking at the slide deck, just that relative returns. It looks like the Mannville is -- I'm going to say, a distant second to the Peavine but comparable to your Eagle Ford Karnes assets. So what does all of this mean for Mannville activity levels in 2024 and beyond.

[Eric Greager, executive]

Thanks, Menno. I think it means we're going to continue to employ our geoscience exploration program. You know what you and I talked about the success that our 2 geoscience teams have had across the heavy oil fairway. We're going to continue to fund that exploration program with what we believe to be a unique petrophysical understanding of the rock, and this has led to the success of Peavine. It has led to the Waseca at Cold Lake, and it has led to additional extensions. And so it competes very well in our portfolio, as you suggest, and it's a good problem to have. WCS basis dips have widened a little bit here in Q4, but we fully anticipate those will narrow back up in 2024. And as TMX starts line fill and comes on delivery.

So we're very confident that the heavy oil fairway will continue delivering new discoveries, new accumulations as well as continued extensions around the places where we've had good success already. So very fond of the heavy oil fairway, very fond of the place that it lives in our portfolio and fully expect to continue funding. The good news is with the very significant cash flows coming out of our Gulf Coast asset, that's 60% of our production priced at a premium to TI, those significant cash flows not only carry the development freight in the U.S. along the Gulf Coast and the Eagle Ford, but also provide very substantial cash flows back into the business so we can continue leaning into all the rest of the strength of the portfolio, continue exploring and developing places like the Pembina Duvernay and the exploration success in Peavine, Waseca, Cold Lake, in around the [indiscernible] Morinville, and all the other places where we are currently excited to explore.

[Menno Hulshof, analyst]

Terrific. And my follow-up is on the share buybacks, a big step up in October. Can you remind us of your overall strategy? Is it programmatic or more opportunistic? How do you -- how does your measure of intrinsic value factor into the allograft are day to day? And is it possible that we see Baytex participate in the next Juniper secondary, which is coming up pretty quickly potentially?

[Eric Greager, executive]

Yes. Yes. So to put a time frame on that last part, Menno, you recall that it was three escrow periods, 90 days, 90 days, and 90 days, each representing 1/3 of the total block. And so the first 90 days executed an overnight bought deal, not us, but Juniper executed an overnight bought deal, and that was September 18, I believe. The next 90-day escrow period will expire on December 17, I believe. And the question around us participating is really a legal and regulatory one. As long as Juniper holds more than 10% of our total outstanding shares, we are prohibited from participating as a buyer in that book. And Juniper currently holds, I think, right at or just under 12%. And so I don't think -- as much as we would love to, I don't think we will be able to participate in the book. And it's the same reason we couldn't participate when they were at a little over 18% and took it down to 12%.

The good news is there was a lot of demand for the shares it traded well, and we certainly do expect the next book to do just as well. So what I would say around the NCIB is, we expect to be programmatic and opportunistic because right now, we're undervalued. So it's a great opportunity to be buying back shares at a pretty good pace. And to do so on a kind of a cost averaging basis, which is the programmatic element of the NCIB. We really like the NCIB because it has this cost averaging functionality but also because as a company, we go in and out of blackouts, and so we can set up instructions and let it run through the blackout whereas if we were being opportunistic that would have to line up with an open window, and that doesn't always happen.

So right now, we're doing both programmatic and opportunistic but it's because we're undervalued and both present themselves, but it's all taking place via NCIB, just to be clear. And then I would say, relative to intrinsic value, I mentioned a couple of times already, we're not currently close to our fair value as we see it. So with the discount, we're buying back as much as we can and intend to continue at a pretty aggressive pace through Q4 of '23. There will be a time, I suppose, if we're really fortunate that the share price begins to approach fair value. I hope that's the case. That will be a good problem to have. And one of the linkages we really like here is as we buy up and take out shares -- outstanding shares, and let's just say for the sake of argument at an NCIB limit of 10% per year, then every year, we could rebase the fixed base dividend by that same amount because you've taken out those shares.

The total quantum of fixed base dividend would decline over time on an absolute value basis. And so that would give us the opportunity to rebase it periodically. And that's a linkage we really like. To be clear, we haven't announced that plan, but it is a linkage we like because it creates a systematic approach to share repurchases and your fixed base dividend. So that's something we like, and it also helps answer the relationship between current share price, intrinsic value and other ways to return capital to shareholders. So let me just pause there, Menno and see if you want to follow up.

[Menno Hulshof, analyst]

No, that was really thorough, Eric. That's it from me.

[Operator]

Our next question comes from Amir Arif of ATB Capital.

[Laique Ahmad Amir Arif, analyst]

Just a couple of questions on the Eagle Ford. Just can you give us a sense of the cadence of drilling plans in the Eagle Ford, I think you brought on 22 net wells roughly this quarter, let's drop into 11 next quarter. Is this -- is it more of a level-loaded program on your operated asset and you just sprinkle in the non-op wells when they come in? Just trying to get a sense of how '24 drilling activity will look in the Eagle Ford on a quarterly basis.

[Eric Greager, executive]

Yes. Q4, on a quarter-over-quarter basis, Amir, there's going to be some lumpiness. It has seasonality impacts to it, broadly speaking, quarter-over-quarter, but then specifically in Q4 and specifically because we have a substantial non-op asset, the capital that gets allocated to the non-op assets in Q4 is, of course, beyond our control. And if the operator pulls back on capital in Q4 because that's -- they've essentially spent the capital and developed a program that they wanted to develop then that sort of kind of is what it is.

On the operated side of the business, we try to run the businesses as operationally efficient as we can. And for our operated Eagle Ford position, this means 2 rigs, level loaded, running basically full time. And those will feed 1 frac crew at the tailgate of the rigs, clearing the DUC inventory that comes off the drilling program. And that will be a little bit lumpy based on pad size and some seasonality effects. But generally speaking, our operator program will be more level loaded, I think, but Q4 is definitely seasonality related towards the end of the year and related more toward the non-op assets.

[Laique Ahmad Amir Arif, analyst]

And then just on the operating cost side. The third quarter results were $12.57 a BOE. I know you mentioned there was some additional work progress going on in that quarter. Can you give us a sense of your comfort level and bringing that number down below $12 into Q4 to submit the updated guidance?

[Eric Greager, executive]

Yes. The -- I think you're referring to -- you're talking about OpEx?

[Laique Ahmad Amir Arif, analyst]

OpEx.

[Eric Greager, executive]

Yes. Yes. Yes. Okay. So it's come down by a couple of bucks on a unit basis since closing of the deal, and that's certainly related to the blending effect of the lower cash cost structure along the U.S. Gulf Coast and just the dilution and blending effects of that lower cash cost structure. We always continue to work on both sourcing labor costs and just operational efficiency to maintain as best we can flat to declining. I think over time, we're going to see probably consistent but light downward pressure on those costs. That is to say, I think if there's a bias, it's biased downward, but it's not going to be, I think, earth-shattering in terms of just how much it moves the needle. So from $12.75 a BOE, is it going to dramatically drop under $10 for 2024? I don't think so.

What I would say is we'll probably see consistent steady downward pressure on that number as we continue to make -- yes, as we continue to make improvements operationally, we tend to continue to do the things that work and not repeat the things that don't work and squeeze out waste and access out of that system. I would target $11 to $12, if I were pushing out into 2024 as a range. And I think that would be pretty responsible in terms of a '24 cost range.

[Laique Ahmad Amir Arif, analyst]

Got it. Appreciate that. And then just final question. Shifting gears over to the Duvernay. You have 6 wells there now that you brought on. You've got some good production results behind it. Can you give us a sense of what your next steps are in the Duvernay?

[Eric Greager, executive]

Yes. Yes. So we're very excited about the Duvernay. I couldn't be more proud of the team. We have built really powerful models, statistical models, mathematical models and continue to populate those models, build those out, history match those models and converge on results that we think will continue to push higher going forward. But as you know, we're also rigorous in terms of our commercial expectations, and we want to do this on a basis that is systematic. And so I would expect -- even though we don't have the budget built for 2024 yet, I would expect more than 6 wells, and I would expect probably less than 9 wells.

So somewhere between 6 and 9 is a reasonable step up as we approach kind of the second year of demonstration, probably the last year of demonstration if I were to lean in a bit and then we'll step up the pace of development after 2024. So there's still more science to do. We want to better understand all the nature of variability, but we've got a lot of data, both delineation and all the various independent variables that drive variation in the output. We've got a strong understanding of those. And so I think next year will be another really good year of development in terms of performance and cost and another year of really strong demonstration toward full commerciality and development -- full development pace.

So let me pause there, here and see if you've got a follow-up on the Duvernay.

[Laique Ahmad Amir Arif, analyst]

No, that was great color.

[Operator]

Our next question comes from Jasper [indiscernible] of [indiscernible].

[Unknown Analyst]

Most of my questions have already been answered. But I have one about the blending expenses, which has been -- have been trending down for the prior year. Could you add some color to this? And what we could expect blending expenses per barrel of heavy oil to average for next year?

[Eric Greager, executive]

Yes. I'm sorry, I'm not -- Jasper, I'm not quite sure I'm picking up which category of expense you're asking about. Just try me one more time.

[Unknown Analyst]

Sorry, blending expenses. blending.

[Eric Greager, executive]

Oh, blending expense. Okay. Yes, yes, yes. Okay. I would expect that blending expenses are going to be related to the value of condensate, relative to the value of our heavy oil crude stream. So I think the value of our heavy oil crude stream that needs to be blended with the diluent is going to trend up over time. I think that's going to be a benchmark -- at a benchmark level and also at a higher kind of asset-level netback level. And so -- and I think [indiscernible] or all the diluents are probably also going to be linked to that. So maybe the blending expenses are going to be flat to potentially declining a little bit, but I would expect in the same way that I mentioned on OpEx -- on unit OpEx probably slight downward pressure, but I wouldn't expect it to be a real needle mover. I just think it's going to feel like and look like operational efficiency improvements.

[Operator]

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

[Brian Ector, executive]

Okay. Great. Thanks, Ariel. And we do have a few questions that have been submitted from the webcast and so I'll moderate ease now for you, Eric. And there are a number of investors that have reached out this morning, looking for a little bit more color or clarity around our sort of free cash flow allocation policy. So how do we decide between share buybacks growing the dividend and debt repayment. And what are the decisions that go into that type of criteria. And then as a follow-up, an investor asking, should we be paying debt down first prior to share buybacks and dividends. So I think they're all kind of interrelated.

[Eric Greager, executive]

You bet. Those are great questions. And I wish there was just a mathematical calculation one could do to arrive at the precise allocation. But in the end, it boils down to a couple of things. It boils down to subjective judgment on the part of the management team and the Board as well as listening carefully to our investors, right, the shareholder base taking in that feedback and having these conversations. And so as I introduced this idea of the linkage between our buyback program and the idea of potentially rebasing the dividend over time on a proportional kind of basis.

Then we will listen to the feedback on that conversation, and we will try to figure out is the balance of the feedback leaning towards that being a good idea or that not being a good idea or that not being a good idea because as everyone knows, there is a fixed base dividend, which is the way we have it structured, which is a function of the $1 per share or in our case $0.01 per share per quarter paid out obviously quarterly. So that's a function of the share count and then there are variable dividends that can expand and contract on a quarterly basis according to some mathematical model. And then there are special dividends.

And generally speaking, you get less credit in your share price for special dividends than you do for variables and you get less credit in your share price or variables then you do fixed. Because the investment community can largely really begin to build in the return of a fixed base dividend predictably, whereas variables are a little harder and specials are very hard to predict. And so you don't tend to get a lot of value back in your share price for those on a go-forward basis.

So when it comes to what kind of dividend, we tend to lean toward 6 base dividends as a function of shares out, and we like this linkage to our share repurchase plan as a functional linkage between the two. When it comes to the allocation between share repurchases and a dividend, it really is about the -- our view of our cost of equity, relative to our view of the cost of debt on a risk-adjusted basis and then how much you return between the dividend and the repurchase plan as a function of the linkage I talked about.

But when you go away from dividends versus share repurchases and you ask yourself, share repurchases versus paying down debt, if you think about our cost of debt as, let's just call it, 8% for the sake of illustration and then you compare that to our cost of equity, which let's say, for the sake of argument, is in the high teens, potentially 20% based on our free cash flow yield. And then you risk adjust between the riskiness or uncertainty around the share repurchase versus a debt reduction, you would make a little bit of adjustment on that but still 16%, 18% is far higher return than, say, 8% on reduction of debt.

And so on that basis, we would say, when you have such a high free cash flow yield your cost of -- that reflects your cost of equity, and you should pay down the highest source of capital, which is your most expensive source which, in this case, is equity.

And so we would say bias toward paying down your equity or buying back your shares. But as soon as that free cash flow yield comes down, because our share price is appreciating into it, that yield will come down, and it will make that balance harder, which is the natural conversion of share repurchases toward debt repayment. And that's why we've been kind of 50-50 in this allocation. I know it's messy, and I know I said a lot of words. But in the end, these are the considerations we have to roll around with. And in the end, that's the decision we have to make.

Now I also think it's really important to make progress on paying down debt, even though you're comparing an 8% cost of debt capital to 16% cost of equity capital on a risk-adjusted basis, that's still important to pay down the debt. And the reason I think it's important is because for every dollar of debt you paid down within your EV construct, if EV stays the same, our enterprise value stays the same, then $1 of debt reduction moves over to $1 of market capitalization accretion. So there's that linkage as well. In the end, it's subjective.

And for that reason, we're going to have to keep having this conversation, I think. We have to continue listening to our shareholder base. and implementing what feels like scratches the itch of the broadest cross-section of shareholders. Let me just stop there, Brian. Do you think that gets it.

[Brian Ector, executive]

I think you captured it well. Keeping along the same theme, if we were to fully execute on our NCIB program, so purchasing 10% of our funded float during the year, would Baytex consider a substantial issuer bid if the free cash flow supported it.

[Eric Greager, executive]

Yes. I think put very plainly, we would consider it. And have thought about it and talked about it, just like the individual who's asking the question has thought about it. Right now, it's pretty early. I think the NCIB has given us plenty of room and I would anticipate that our NCIB for the July 1, 2024, ended into June 30, 2025, is also going to be substantial in terms of its total number of shares based on the float we project. So we may not have to have that conversation or make that decision soon, but we do consider it for sure.

[Brian Ector, executive]

And then the last question, I think, along this theme of capital allocation and share repurchases. We talked a little bit today about the view that our shares are undervalued and a couple of investors are asking like what do you consider to be the sort of current fair value of our shares there. I don't have a tough question to answer, but I wanted to put that out for you.

[Eric Greager, executive]

Yes, it is a tough one because it depends on your view of pricing. I think if you take some fusion of a consensus estimate, consensus bank forecasts over time combined with the forwards, which I think underrepresent the future price environment. But if you take some fusion of a consensus estimate and a forward strip, maybe that's close. And if you assume that, I think you probably could take some average of the analyst estimates, they're all very good models. Brian and the analysts work carefully together to ensure the models are well informed. And there's not a stale forecast out there. So I would say, taking some average median or central tendency to the analyst target prices might be the best place to look.

[Brian Ector, executive]

Thanks, Eric. And you have to pass this question over to Chad Kalmakoff, our Chief Financial Officer. We talked a little bit about the debt repayment. The question relates more to our debt structure chat. Can you comment on the components of our debt is at floating rate, the interest rates we pay any interest rate swaps associated with our debt structure.

[Chad Kalmakoff, executive]

Sure. Thanks, Brian. Yes. So Q3, like we mentioned earlier, we have CAD 2.7 billion outstanding in debt. In that, we had CAD 1.7 billion of that being our long-term notes. Those are all U.S. dollar denominated notes. So $1.2 billion U.S. dollar denominated notes. Those have interest rates of 8.5% and 8.75%. So USD 800 million at 8.5%, USD 400 million at 8.75%. So obviously those are fixed 2027 and 2030. The remainder of our debt is on our credit facility, that's so we call it CAD 1 billion on the credit facility. That's a floating debt structure. Generally speaking, it's kind of based on the margin, but think of that as kind of SOFR plus [ 2.25 ]. We will keep that flowing, we do not have any integrate swaps against that debt.

[Brian Ector, executive]

Thanks, Chad. And then a couple of questions related to free cash flow. Most of the free cash flow over the last 4 months have been directed towards the share repurchases. And if you looked at our Q3 free cash flow of $158 million, maybe lower than some might have expected. I think there's some seasonality around capital. Eric, can you just elaborate on the free cash flow profile as it relates to our business and capital spending on a quarterly basis and how it averages out over the course of the year.

[Eric Greager, executive]

Yes, there's definite seasonality. So folks remember back to Q1, Q1 is always a strong start to the year and a lot of -- because it's frozen ground, really good operating conditions in terms of the ability to execute a program reliably, although it's cold, you can execute well. And so drilling capital, you really get after your program and that was a significant capital program. And remember, that was Baytex stand-alone. Then in Q2, you've got a lot of production with a lower capital program. So we generated almost $100 million of free cash flow in Q2 as a Baytex stand-alone unit. And then in Q3, as the listener and writer rightly points out $158 million free cash flow. But we spent $409 million in CapEx. And that $409 million, as Brian pointed out, is a function really of seasonality. Q3 is a really good quarter for getting after it.

Lots of drilling and completions activity in all of our active areas across the entire portfolio. And then Q4, we're getting the benefit of a rising production into Q4. So as everyone noticed in our release, we're forecasting 158,000 to 160,000 BOE a day for Q4. And in that strength against a lower capital spend means there's a great deal of free cash flow left over. So free cash flow kind of is what comes out the bottom, and it's very dependent on not only operating cash flow or AFF, but also the lumpiness of your capital program. And the capital program is lumpy because of seasonal effect and at point in the year, also these sort of base effects around budget season that comes at the end of the year, which I talked about earlier. So let me stop there, Brian, and see if that...

[Brian Ector, executive]

And then a couple -- one more sort of financial related question, and I think we'll shift into a couple of more operational conversations, but maybe Chad over to you again on our current WCS hedging program on the heavy oil side.

[Chad Kalmakoff, executive]

So we do have some heavy oil hedges in your Q4, I think, miles hedging maybe 8,000 barrels a day, and they are hedged at around $14 here for Q4. Into 2024, we have pretty minimal hedging on WCS basis. We have a bit of transportation hedging for the first half of the year and then the rest of the year we're unhedged.

[Brian Ector, executive]

Eric, do you want to add some color around our expectations on WCS as we move through 2024?

[Eric Greager, executive]

Yes. Thanks, Brian. I think -- at least from what we've read and the intelligence we can gather, it sounds like TMX will be sort of mechanically complete in Q1 of '24. This is what we read. This is what we're told. And there's a dispersion in data, but the central tendency of the various pieces of intelligence we get seems to point at Q1 mechanically complete. That same dispersed bit of intelligence also tends to point toward line fill, which is kind of already -- some of it is already taking place because this is a big project, and it's been built in segments. I think some of the line fill is already completed, and this is what we've been able to ascertain. And so Q1 mechanically complete, Q1 continuing line fill and really line fill progressing.

And then we're certainly expecting Q2 deliveries through TMX. This is the best information we can gather. I think everyone has access to disperse intelligence on this. So we might all have slightly different collection of data, but that's what we think and that's what we expect. And we think once TMX comes on, in early 2024, we expect the WCS/WTI basis differential to narrow into the kind of $10 to $12 per barrel range. And we think that becomes effectively described by the pipe economics to the U.S. Gulf Coast on the Enbridge mainline.

[Brian Ector, executive]

Thanks, Eric. We're going to shift now to talk a little bit more. We had some questions come in on the assets themselves and the performance during the third quarter. First question relates to the Eagle Ford operated acreage. Eric, the results that we're seeing, are they in line with our expectations and any refracs planned on the assets.

[Eric Greager, executive]

So the answer to the first question is, yes, in line. We've been modeling expectations like this. We've been working through the designs and the well performance expectations. So yes, Q3 meets our expectations, and we feel good about the way it represents the assets on a go-forward basis. We do have refracs plan, and we continue to run -- we continue to think about the refrac program as kind of a parallel, if you like, a sidecar to the primary channel of drilling and completions development, primary capital development in the play along our operated portion of the play, as I described earlier, 2 rigs level loaded running full time through the program. That's a very efficient operation because these 2 H&P rigs are some of the best rigs in H&P's fleet, certainly some of the top-performing rigs in the Eagle Ford. And they've been with Ranger now Baytex for years. So they're very efficient.

And then the Liberty frac crew also have been with the team on an extended basis runs very, very well. So that's clear and DUC inventory. That's a nice level loaded, highly operationally efficient channel of progress on development capital. And then a side car to that is refracs. And the refrac program, there's a lot to think about. There's the candidate selection, which is, can you get in and get out with your workover operations and prep the line or do you have good zonal isolation. And is it a well that you think you can contain the fracture stimulation energy in the fairway or the stimulated reservoir volume that you're trying to refrac. And so there's a lot to think about in refracs, but we're quite encouraged and continue to progress that sidecar channel of capital development in our Eagle Ford. And we're going to learn a lot there from our peers in the area who have more experience doing it. We sit on task groups and technical groups. And so there's a lot to learn, but we're very excited about it.

[Brian Ector, executive]

Eric, can you comment on the range sort of expectations for the current exploratory wells in our 2 new areas here in Western Canada. Just a range of expectations on the program.

[Eric Greager, executive]

Yes. So the [indiscernible], Morinville, we've described these in our prior conversations as 30 to 100 locations each, so the [indiscernible], Morinville, somewhere in that range. I'm confident in the higher end of that range because the lower end has a pretty tight risking on it, that is to say it's heavily risked and I feel good about the fact that we'll probably get higher on the range there in terms of locations in the [indiscernible], Morinville, and similar kind of 30 to 100 locations at the Waseca at Cold Lake.

We're continuing to develop those in Q3 and even today. And so we've got additional multi-lats that we have underway and that we will continue to drill and bring online in Q4. And so there'll be more to talk about in Q4. Even though those are not needle moving assets in terms of the number of locations and the production. They do continue to really demonstrate that this is a substantial footprint across a highly prospective fairway. And we feel really good about the steady diet of both discoveries and the geoscience team leading to new accumulation discovery and extensions. And so that just -- it feels like a steady diet that will continue on.

[Brian Ector, executive]

Eric, I think we're pushing almost an hour. So there are more questions. If we don't get to your questions here, we will try to follow up with you individually. So maybe 2 more, Eric. An investor here asking about the expected cost savings from the merger. Have we achieved what we expected from a synergy standpoint?

[Eric Greager, executive]

We certainly have made a lot of progress. The basis of the merger between Baytex and Ranger was not ultimately predicated on synergy savings. The synergy values were pretty modest in the outset. And we have accomplished all of those that we set out to accomplish. Again, they were pretty modest. It was eliminating duplication in things like back office, financial audit, IQRE or independent reserves audit, the redundant boards, the redundant leadership at the top part of the organization. So all of those, including a whole bunch of kind of redundant IT and software subscriptions, all of that has been extracted.

And so yes, given the fact that they were pretty modest to start with, we have achieved them. There's still a lot of additional meat on the bone, and we will continue to drive additional savings forward. And that will be -- that will appear like operational efficiency over time, the way we described, say, the OpEx, the unit OpEx and the blending expenses over time, just consistently getting a little bit better over time. So that's the way I think about synergy progress.

[Brian Ector, executive]

Another question, a little bit different, more of an ESG focus and it might relate it to our Duvernay completions. But the shareholder is asking if Baytex has any interest in low energy or chemical or filter wastewater treatment technology. So it's a bit of a different question that I thought I would ask.

[Eric Greager, executive]

Yes. So one of the ways to think about this is in both the Viking and the Duvernay, we are working very hard to lower our freshwater intensity. And in particular, in the Duvernay, for example, we use municipal wastewater affluent as makeup fluid for fracture stimulation. And that's particularly helpful because it helps lower the freshwater intensity of the operations. And in the Viking, of course, we use effluent from our [indiscernible] Thermal operation, and we use that as makeup fluid for a fracture stimulation in Viking. So these are really helpful kind of intensity measures on an ESG perspective -- from an ESG perspective in our fracture stimulation work in Canada. And we're always looking to apply new technologies to creating better freshwater streams, less expensive freshwater streams and, in particular, the ability to use wastewater sources as freshwater for makeup.

[Brian Ector, executive]

Two last quick questions, Eric, I promised breakeven on oil pricing.

[Eric Greager, executive]

Breakeven on oil pricing down into the, I'd say, low to mid-40s across the entire portfolio. And getting better as we squeeze more efficiencies out of both the capital program and the operating expense program.

[Brian Ector, executive]

And we're going to wrap up with this one question because I know it's something that Eric, you're fairly passionate about. And this comment comes from a shareholder who says that there are others out there and shareholders that are frustrated with our share price, unable to gain traction besides the buybacks. How do you plan to work to get that Baytex share price reflective of the fair value that you see in them.

[Eric Greager, executive]

Yes, it's a great question. I, too, feel like it's been a long time. I'm reminded by the fact that we started this conversation about the merger between Ranger and Baytex on February 28. And it was several months to close, and we released just a partial Q2. So Q3 is really the first full quarter. And when you find yourself in a show-me status or show-me mode, basically, all you could do is deliver results. And I think because Q3 is the first 4 quarter of delivering results, it really is the first opportunity for us to have showcased the full strength of the portfolio, the full strength of the assets, the skills and talents and experience of our team. And I think Q3 will go a long way to firming up the confidence that others have in the asset base and the team that I've had all along.

Q4 will also reinforce that and then full year and then reserves. But it is a process, but it takes time to show the world because these have to come out on quarterly cycles. And so here we are in November, releasing our first full quarter of results. And I'm quite pleased and expect the good performance to continue through the year and well into the future.

[Brian Ector, executive]

That's terrific, Eric. Thanks everyone for spending near at the last hour with us today. This is going to conclude the Q3 conference call and webcast. Thanks everyone for participating. Have a great day.

[Eric Greager, executive]

Thanks, everyone.

[Operator]

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