Tourmaline Oil Corp
TSX:TOU
Earnings Call Analysis
Q3-2023 Analysis
Tourmaline Oil Corp
Tourmaline's third quarter of 2023 was marked by strong cash flow, with a noteworthy $878 million generated, translating to $2.55 per diluted share. Their adept management of funds led to significant free cash flow amounting to $332 million or $0.96 per diluted share. Capitalizing on this fiscal stability, Tourmaline declared a special dividend of $1 per common share, showcasing their ability to reward shareholders amidst robust financial performance.
As the financial year progressed, Tourmaline's free cash flow forecast for 2023 experienced a positive revision, reaching an impressive $1.9 billion. Their net debt as of September 30, 2023, stood at $880 million, a manageable 0.3 times the annualized cash flow of Q3, which was about $3.5 billion. Such fiscal prudence indicates sound financial strategies are at play, ensuring the company's agility in handling liabilities.
Strategic movements were evident, as Tourmaline announced the acquisition of Bonavista Energy Corporation for $1.45 billion, with the transaction anticipated to close in the latter half of the month. The deal consists of an equal split between Tourmaline common shares and cash, discounted by Bonavista's net debt at closing. With this acquisition, Tourmaline is poised to solidify its market standing and augment its asset portfolio.
The company successfully hit the upper echelon of its production guidance, averaging 502,000 Barrels of Oil Equivalent (BOEs) per day in the third quarter. Even with planned plant turnarounds and storage injections mildly hampering operations, Tourmaline's annual production guidance remains steady at 520,000 BOEs per day, optimistically aiming for over 600,000 BOEs per day by the year's end.
Looking ahead, the 2024 average annual production is projected between 600,000 and 610,000 BOEs per day, with a formal guidance set at 600,000 BOEs per day. Plans are in place to enhance production from Bonavista's assets by 2025, dovetailing with expected higher gas prices. Furthermore, Tourmaline is transitioning to become one of Canada's premier liquids producers, expecting an average liquids production of over 140,000 barrels per day.
The third quarter's financial solidity was further underscored by an increase in the base dividend from $1.04 to $1.12 per share, an indication of the company's healthy balance sheet position, which was bolstered by the value of their shares in Topaz Energy Corp. This, coupled with sustained free cash flow, underscores Tourmaline's commitment to shareholder value.
Tourmaline's average realized natural gas price significantly surpassed the benchmark, achieving CAD 4.56 per mcf against the AECO 5A benchmark price of CAD 2.64 per Mcf. The company has strategically hedged substantial daily volumes for the upcoming year and has unsheathed exports aimed at premium markets, signaling confidence in market position and pricing dynamics.
With strategic foresight, Tourmaline is set to augment its natural gas exports to 1.08 billion cubic feet per day by the year's end. Additionally, a long-term Henry Hub netback arrangement promises to channel about 60 million cubic feet per day to the U.S. Gulf Coast starting November 2026, highlighting their commitment to market diversification and long-term growth.
Capital expenditures for 2023 have been revised upwards to approximately $1.825 billion, partially due to the assimilation of Bonavista-related expenses and moderate inflation. The Board of Directors has sanctioned a $2.15 billion capital budget for 2024, a reflection of a robust drilling program that includes activities on Bonavista assets. These investments are expected to drive substantial cash flow and free cash flow in 2024, amounting to $4.5 billion and $2.2 billion respectively, painting a picture of aggressive but calculated financial planning.
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Good morning, ladies and gentleman, and welcome to Tourmaline Q3 2023 Results Conference Call. [Operator Instructions] Please be advised that this call is being recorded on Thursday, November 2, 2023. I would now like to turn the conference over to Jamie Heard. Please go ahead.
Thank you, operator, and welcome, everyone, to our discussion of Tourmaline's results as at September 30, 2023, and for the 3 and 9 months ended September 30, 2023 and 2022. My name is Jamie Heard, and I am Tourmaline's Manager of Capital Markets. Before we get started, I refer you to the advisories on forward-looking statements contained in the news release as well as the advisories contained in the Tourmaline annual information form and our MD&A available on SEDAR and our website. I also draw your attention to the material factors and assumptions in those advisories. I'm here with Mike Rose, Tourmaline's President and Chief Executive Officer; and Brian Robinson, our Vice President of Finance and Chief Financial Officer. We will start by speaking to some of the highlights of the last quarter and our year so far. After Mike's remarks, we'll be open for questions. Mike, please go ahead.
Thanks, Jamie, and welcome, everybody. Thanks for dialing in. We are pleased to review our third quarter results, outline our '24 plans and answer questions you may have. So firstly, a few highlights. Third quarter cash flow was $878 million or $2.55 per diluted share. We generated free cash flow in the third quarter of $332 million or $0.96 per diluted share. And that enabled us to declare a special dividend of $1 per common share, and that was paid on November 1. The company has distributed total dividends of $6.52 per share, inclusive of the November 1 special since December 1 of '22 and that's an implied 9% trailing yield.
Full year '23 free cash flow forecast is now $1.9 billion, so up. September 30, 2023, net debt was $880 million, which is 0.3x Q3 '23 annualized cash flow of $3.5 billion. Third quarter net earnings were $275 million or $0.80 per diluted share. And as you know, in October, we entered into an agreement to acquire all the shares of Bonavista Energy Corporation for $1.45 billion. That consisted of $725 million in Tourmaline common shares and $725 million of cash, less Bonavista's net debt at closing. And the closing of the transaction is still expected to occur in the second half of this month. Starting with production. Our third quarter average production of 502,000 BOEs per day was at the higher end of our guidance of 495,000 BOEs to 505,000 BOEs per day. Third quarter was reduced by our planned plant turnaround, which amounted to a 16,000 BOEs a day impairment in the quarter as well as our planned storage injections in California and Dawn. Our 2023 average production guidance remains at 520,000 BOEs per day, and we expect exit '23 production of over 600,000 BOEs per day. And that would include the acquired Bonavista volumes. Inclusive of the Bonavista assets on a maintenance-only capital budget, we anticipate 24 average annual production to range between 600,000 BOEs and 610,000 BOEs per day, and the formal guidance we're using in the 5-year plan is 600,000 BOEs per day. We do plan to grow production from the Bonavista assets in 2025, and that will be into an anticipated higher gas price environment. 2024 average liquids production of over 140,000 barrels per day is now forecast as the company evolves into one of the largest Canadian liquids producers. Tourmaline is Canada's largest natural gas producer with forecast production of over 2.7 Bcf per day in calendar 2024.
Briefly on financial results. As mentioned, Third quarter cash flow was $879 million on total CapEx of $565 million. EP spending was $533 million, so a little under forecast. And we generated free cash flow of $332 million in the quarter. As of September 30, 2023, the company from a balance sheet perspective is actually in a surplus position when you include the value of our 45.1 million shares of Topaz Energy Corp. And the continued strong free cash flow that we generated during the third quarter as well as the forecast free cash flow for the fourth quarter of this year allowed the company to pay the previously announced special dividend of $1 per share. And we also increased the base dividend from $1.04 to $1.12 per share on an annualized basis, and that's effective as of the December 2023 quarterly base dividend payment.
Looking at marketing. Our average realized natural gas price for the quarter was CAD 4.56 per mcf, and that was significantly higher than the AECO 5A benchmark price of CAD 2.64 per Mcf. In the fourth quarter of this year, we have an average of 755 million per day hedged at a weighted average fixed price of CAD 5.07 mcf. For '24, the company has an average of 722 million per day hedged at a weighted average price of CAD 5.35 mcf, an average of 119 million per day hedged at a basis to NYMEX of minus USD 0.05 per mcf, and we have an average of 833 million per day of unhedged volumes exposed to export markets in '24.
And of that volume component, 65% is exposed to the premium export markets, which for us are the U.S. Gulf Coast, our Western U.S. hubs, JKM and Sumas. The company's exposure to Western U.S. markets will increase this month with the addition of 82 million per day of transportation capacity. With this addition and others, the company's natural gas exports will reach 1.08 bcf per day by exit of this year. We have further diversified our natural gas marketing portfolio by entering into a long-term Henry Hub netback arrangement, and that will move approximately 60 million per day to the U.S. Gulf Coast. And that will expect -- we're expecting that to commence in November of 2026.
And we joined the NeeStaNan venture as an industry supporter, that's an indigenous-led project that will create a multiproduct utility corridor, including nat gas, and that will connect Alberta, Saskatchewan and Manitoba to Tidewater on Hudson's Bay. And the project ultimately involves a port for containers, potash and other prairie products and envisions an electrified LNG facility actually on Hudson's Bay.
Looking at our capital budget and financial outlook. As mentioned, third quarter CapEx was $533 million on EP. Full year '23 EP capital spending is now anticipated to be approximately $1.825 billion, and that is up from the prior $1.675 billion. That increase includes the incorporation of anticipated Bonavista related capital expenditures post closing this quarter, incremental inflation of approximately 5% over forecast levels, as that happened as we locked in services during the second and third quarters of this year for the second half '23 to first half '24 EP season.
And also, we're accelerating the fracking of 2 pads into '23 from fourth quarter of '23 -- from first quarter of '24 due to faster realized drilling times. Our Board of Directors has approved a full year '24 EP capital budget of $2.15 billion, that reflects a 14 to 15 rig program, and that includes $225 million associated with the Bonavista assets. That '24 EP program is expected to deliver cash flow at strip pricing of $4.5 billion and free cash flow of $2.2 billion, and those are both up from previous estimates.
And as in previous years, we are strongly committed to returning the majority of free cash flow to shareholders, and we plan to continue our practice of quarterly special dividends during calendar 2024. Our updated 5-year plan incorporates modest growth from the Bonavista assets commencing in 2025 as well as the deferral of the North Montney Phase 2 Conroy development by 1 year. And that deferral allows us to spread out facilities CapEx, evaluate potential Phase 2 facility electrification options and it results in a significant increase in free cash flow, particularly in that '26 to '28 time frame.
And of note, between 2022 and 2028, Tourmaline anticipates organically growing the Northeast BC Montney Gas Condensate complex, production or volumes by over 125,000 BOEs per day, and that's without the North Montney Phase 2 Conroy project.
A brief EP update. We continue to operate all 13 drilling rigs and 3 to 4 frac spreads across our 3 EP complexes. And we anticipate adding 1 to 2 drilling rigs in calendar '24 to accommodate drilling on the Bonavista assets. During the fourth quarter of this year, we will bring 76 new wells onstream, and that will drive very strong Q4 average production volumes and a strong 2023 production and exit level. During the third quarter, we delivered a new pacesetter well in the North Montney, 4.91 days from spud to rig release for a 4164-meter horizontal well.
On the exploration front, as of the end of September, the company has made 19 new pool, new zone discoveries and drilled 1 uneconomic marginal oil well since we started that exploration program well over 3 years ago. The program has yielded 1.26 Tcf of booked 2P reserves at year-end '22 and has also added an estimated 957 Tier 1 and Tier 2 drilling locations to an already very large inventory.
Looking at the North Deep Basin, we are planning a new facility project that will optimize production at the existing Musreau-Kakwa plants that we operate and it's expected to add 15,000 BOEs per day during '25 and '26, again, into that anticipated stronger natural gas pricing environment. We also completed the acquisition of assets from White Horse Resources Limited during the third quarter of '23 for $19.1 million. And this acquisition expands our landholdings and inventory adjacent to a Cardium oil discovery that we made in the first quarter of this year in the Resthaven-Kakwa area, and we provided some details on that well.
And on the board front, we're very pleased to announce that Christopher Lee has been appointed to our Board of Directors, and he was at his first meeting yesterday. So I think that's enough on the review of the press release, and we're more than happy to answer questions that you may have.
And ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] And your first question comes from the line of Jamie Kubik from CIBC.
Just a question related to the Bonavista deal. Tourmaline has been relatively quiet in the past couple of years on the M&A front. Can you just talk a little bit more about what the Bonavista acquisition brings to the company and maybe a little bit more on Tourmaline's appetite for acquisitions in the current environment?
Sure. We've been tracking Bonavista and the progress of that company for well over 2 years as they improved their balance sheet, eliminated debt and moved into free cash flow-generating mode.
And that's one of our key criteria when we complete M&A is that the free cash flow yield from an acquisition has to be as good or better than what our organic 5-year EP plan can deliver and that was certainly the case with the Bonavista transaction. It's a significant addition to our existing Deep Basin complex. We see opportunities for cost reduction and production optimization and partly because they've been really on a maintenance capital budget for several years.
We see lots of opportunity for improvement and a large inventory and ability to grow the production, and we'll do it modestly as mentioned, and we'll start that in '25 when we think gas prices will be better than '24. Although '24, it's just hard to call. I think with the start-up of LNG Canada and the Gulf Coast LNG expansion. I think we all expect stronger pricing in 2025. As far as further M&A, we're always looking. We always have been, but we've got very strict criteria before we want to consummate any kind of deal. And being that we've kept our geography the same with the 3 core complexes, we're well versed in kind of what's out there. So hopefully, that helps, Jamie.
Yes, that's good. And then maybe second question for me is just there's been a fair bit of commentary out there about the increase in service activity that could a company, the LNG Canada project coming up. Have you seen this come through in any of the recent pricing? And has Tourmaline contracted services to sort of get ahead of this would be my second question.
More from a facility construction standpoint or just drilling and completion?
Yes, both, I suppose, Mike.
Okay. Well, we have contracted our drilling and completion services and indeed, we're 5% higher for that next tranche of activity than what we were originally forecasting. So that's all worked into our balance of '23 and '24 capital program. our Montney Phase 1 development, we're already working on some of the components of that, and we've assembled a piece of the infrastructure already for that. So I think we're reasonably well insulated from further facility increases.
[Operator Instructions] Your next question comes from the line of Mike Dunn from Stifel .
A couple of questions for me. Firstly, on the Cardium oil discovery, just wondering if you could frame what the economics might look like for those wells under development mode and maybe what well costs might look like? And I'll follow-up with a second question after.
Okay, sure. Well, it's a strong well. It looks like somewhere between 250,000 and 300,000 barrels, our estimate of recoverable oil and probably 2 Bcf with that, that was off a 3-well pad, but we only drilled 1 Cardium location. We actually made 2 other new cool discoveries off the same bed. So 3 horizontals on that pad into 3 different zones. So as we move into development mode, we'll do a delineation pad in '24 and then develop in '25. We expect to continually reduce the drilling and completion costs. So economics are obviously very strong with current pricing. So you're looking at IRRs north of 50% on something like that, reserves of that nature and that deliverability and well performance profile. So yes, very strong, and the gas will be connected to our Musreau plant. So we really have the gas solution already in place.
Great and then just on your options or how you're looking at how electrification might occur for your North Montney Phase 2 project? Maybe just -- if you could just frame for me what the hurdles are there? I have heard that electrifying gas plants north of Peace River is a lot more challenging...
Yes. We're looking at it, lots of options. It's not clear yet what will happen to the grid. The other way you can electrify is generate it with natural gas and couple that with CCUS. So we're evolving all of those potential solutions along. And as we complete that evolution, we thought appropriate move Phase 2 by 1 year. But really, our plan -- we focused on shareholder returns rather than very rapid growth. So we're very happy with what the 5-year plan looks like and the spreading out of facility expenditures. So it's -- over the 5 years, it's a 33% increase in free cash flow that we can, the vast majority of which will be returned to shareholders.
And your next question comes from the line of Dennis da Silva from Middlefield Group.
Good Q3 results. Question on the CapEx for 2024. Maybe give a little more insight into the increase in the plug and perf your early days on that how you're maybe translating some of the anticipated improvements in all results into your production for '24 going forward?
Sure. Well, I'll sort of not answer those necessarily in the order you asked them. We don't incorporate improved production from trialing of new technology until it's trialed and we've been able to evaluate the results. So we just used existing performance curves as we build up '24 and performance over the 5 years. The 2024 capital budget, there's $225 million in there for the Bonavista asset.
So the EP spending '24 that we put out yesterday compared to the guidance that was out there, the EP spending is actually down when you incorporate Bonavista. We do fund the exploration program and what we call our environmental performance, improvement initiatives. So that's the diesel displacement and methane mitigation. That's funded out of free cash flow and gets added on to that $2.15 capital budget.
So we thought we've done a pretty good job holding it. And in fact, as I mentioned, EP spending is actually down a little bit. As far as plug and perf and some of the more liquid-rich horizons, in the Montney, particularly in the North Montney, we've been doing that, and we'll continue to evaluate what's the best option going forward. And our main focus is economic return and obviously, we look at EUR and we look at well performance, but we're driven by economic return, and that's kind of the sort of guiding philosophy in that change to the 5-year plan as well. We want to make as much money and be as profitable as possible. And so we're really excited about what that new plan looks like.
And your next question comes from the line of Fai Lee from Odlum Brown.
Mike, I was just wondering about your exposure to AECO more in the '25 to 2027 time frame with LNG Canada coming on. Are you anticipating having more exposure than you currently have to the AECO pricing or something similar to I guess...
Yes. No, thanks, Fai. I might let Jamie jump in on that one.
Yes, we do generally grow our exposure and we have this in the presentation on Slide 23, but we're happy with the growing exposure to AECO in '25 and '26, and that's because it also coordinates with the start-up of LNG Canada, which we think will be a bullish and tightening aspect of the supply and demand dynamics in the WCSB. We are -- we have been, over the last 2 years, adding export exposure into the West Coast, we've added, as we mentioned in the press release today, additional exposure into California.
And these markets have been extremely high premium gas price markets for us in 2023, and we anticipate also them to be at a high premium in 2024. But in '25 and '26 as we bring on the Phase 1 of Conroy, we are happy to have those exposed volumes sitting into the AECO bucket for now because we see AECO as a tight and very competitive market for our gas with the start-up of LNG Canada.
Okay. Yes, I did see the slide on increasing exposure, I just want to make sure if that was going to change dramatically as time passes.
Look, in general, the slide also incorporates the growth we have folding into the plan. We don't forecast added transportation agreements. So over time, we're always looking to augment our portfolio into premium markets. And so I think it is reasonable for you to anticipate there to be small changes to the physical nature of this plan. And of course, every year, we're looking to tactically add hedges that add value to the portfolio. So we're not a structural hedger, but we do like to look out the curve and find areas in each of our markets, including our local one where we can protect exposure, particularly often in the summers. But in general, our view is that '25 and '26 are going to be buoyant gas price markets and likely offer prices higher than they are today. So I don't think we're that aggressive on looking at locking in any of the pricing in '25, '26 at the current time.
And there are no further questions at this time. I would like to turn it back to Jamie Heard for further remarks.
Well, we thank you all for dialing in today and joining us on this conference call, and we hope you have a good rest of your day.
Thank you, presenters and ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.