Tourmaline Oil Corp.

Good morning, ladies and gentlemen, and welcome to the Termaline Q1 2023 results conference call. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. To ask a question, please press star 1 on your touch-tone phone. If at any time during this call you need assistance, please press star 0 for the operator. This call is being recorded on Thursday, May 4, 2023. I would now like to turn the conference over to Jamie Hurd, Manager of Capital Markets. Please go ahead.

Thank you, Operator, and welcome everyone to our discussion of Tourmaline's results for three months ending March 31st, 2023 and 2022. My name is Jamie Hurd, 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 on the Tourmaline Annual Information Forum and our MD&A available on CDAR 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 Robertson, Vice President of Finance and Chief Financial Officer. We will start by speaking at some of the highlights of the last quarter in our year so far. After Mike's remarks, we'll be open for questions.

Mike, please go ahead. Thanks, Jamie. So welcome, everyone. Good morning. We're pleased to review Tourmaline's Q1 results and answer questions you may have. So firstly, some highlights. First quarter cash flow was $1.127 billion, or $3.28 per diluted share. We generated free cash flow of $525 million in the quarter, or $1.53 per diluted share, and that allowed us to declare a special dividend of $1.50 per common share. We had record first quarter 23 average production of 526,000 BOEs a day. We continue to expect full year 23 free cash flow of $2 billion. And our March 31 net debt was $709 million or approximately 0.2 times 2023 full year forecast cash flow of $3.9 billion. Touching on production, as mentioned, first quarter averaged 526,000 BOEs a day with liquids production of a little over 114,000 barrels per day. And that's despite the Pemina NGL pipeline system interruption, which reduced production by 8,000 BOEs a day for approximately six weeks. Current total oil and liquids production has recovered to the 118,000 to 123,000 barrel per day range over the past month. Q2, 23 average production range of between 500,000 and 515,000 BOE per day is currently expected. as we begin our injection season into our storage reservoirs, and we execute our Q2 plan maintenance programs for both own account and third party. Encouragingly, the April production average has rolled up to approximately 531,000 BUEs per day, which is a record, and that is prior to storage injections, which have happened in the month as well. And our full year 23 average production guidance between 520,000 and 540,000 BOEs per day remains unchanged. Looking at financial results, as mentioned, first quarter cash flow was $1.13 billion on total capex of $595 million, generating free cash flow of $525 million. In 2023, at strip pricing as of April 14th, The company continues to expect to generate cash flow of $3.9 billion or $11.22 per diluted share and free cash flow of $2 billion or $5.80 per diluted share on unchanged EP spending of $1.7 billion. That forecast 23 cash flow remains unchanged from the previous forecast despite 2023 NYMEX gas prices declining by 12% since our last update. And this is a reflection of our strong and continuously improving natural gas market diversification portfolio. Similarly, 24 cash flow has actually improved 3% since our last forecast update. Given that strong free cash flow generation outlook for 23, the company's elected to increase the quarterly base dividend effective this quarter to $1.04 per share on an annualized basis from the current annualized dollar per share and as well declare and pay a special dividend of $1.50 per share on May 19th, 23, to shareholders of record on May 11th. Looking at marketing, our average realized NACDAS price was $6.18 per MCF Canadian in Q1, significantly higher than the ACO 5A benchmark price of $3.28 per MCF Canadian for the period. We have an average of $801 million per day hedged at a weighted average fixed price of $558 per MCF Canadian, an average of $137 million per day hedged at a basis to NYMEX of $0.46 per MCF US, and an average of $731 million of unhedged volumes exposed to export markets in 2023. And of that $731 million, 71% is exposed to the premium markets such as the U.S. Gulf Coast, JKM, Malin, PG&E, and Sumas. We commenced delivery Jan 1 of our $140 million a day to the Chenier Sabine Path LNG facility, where our average Q1 realized price before liquefaction and shipping fees was $19.44 per MCF U.S. The $23 JKM strip price as of April 14th was still $14.87 per CF US. And we also have $31 million a day hedged at a weighted average fixed JKM price of $31.26 per MCF US in 2023. And importantly, as of April 1 of this year, we were able to increase our natural gas volumes exported to Western US markets by $100 million per day to a total of $445 million per day through the completion of the Westgate expansion project. A few comments on the E&P program. We operated maximum 15 drilling rigs during Q1. We're currently operating four rigs, three of them in BC as we're in breakup. We drilled a total of 71 net wells in Q1. We completed 68 net wells in the quarter and we have an inventory of 38 ducts Entering q2 so a little higher on the duck front than than past years Importantly terminating has 388 valid drilling permits in Northeast BC now having received an incremental 82 Permits thus far in 23, which is certainly a positive development A little bit of an expiration update. As of year end 22, we had made 15 new pool or new zone discoveries since starting the expiration program well over three years ago. And in our year end 22 reserve report, we booked 1.26 TCF equivalent from those new pools. And current mapping of these pools indicates the potential for a further 3.2 TCF of raw natural gas that will delineate with follow-up drilling over the next couple of years. We also have made three additional new pool discoveries so far in 23 that are outside that reserve report. And as of year end 22, this program's added an estimated 749 Tier 1 and Tier 2 drilling locations, which get added to our existing deep inventories. On environmental performance improvement, or what we like to call EPI, looking at our diesel displacement efforts between July of 17 and the end of this first quarter, we've now displaced 106.5 million litres of diesel in our drilling and completion ops, resulting in a net cost savings of 103 million, and that includes the cost of the replacement NAT gas. And then on April 18th of this year, we announced the next step in the Diesel Displacement Initiative. Tourmaline and Clean Energy Fuels Corp. will jointly build and operate a network of up to 20 CNG stations along key highway corridors across Western Canada. And the initiative allows for the use of readily available natural gas to significantly lower emissions from heavy-duty trucks and other commercial transportation fleets. And there's lots of long-term upside to this initiative, both for emissions reduction and for building natural gas demand. So that's the end of kind of the formal remarks. So we will be pleased to take questions you may have.

Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star followed by the one on your touchtone phone. If you would like to withdraw your request, please press star followed by two. And if you are using a speakerphone, please lift the handset before pressing any keys. First question comes from Jeremy McRae at Raymond James. Please go ahead.

Hi, Mike. I just want to talk about some high-level strategic questions here, just on your exploration plays. As any of the results kind of built into your five-year plan, is this all on the monty? Can you give us any indication of you know, if there's, you know, how big this really could be relative to where your current production is here today?

Well, we think it's material already from a reserve adding and inventory standpoint. I think in the commentary over the past 18 months, we have set up those 15 that are in the year-end 22 report. Three we think are material, and there's one in BC and one in the Deep Basin, just to give you a sense of geography. And, yeah, they're material to what we're doing, and they do – get rolled into the inventory and, in some cases, into the shorter-term five-year plan.

Okay. And Montney, I'm guessing, in BC, or is it other formations that you guys are looking at here too?

Well, we do like to look at the whole section, especially when we're talking expiration. So, I mean, the important thing is they're all within the same geography. They all reach our existing infrastructure network. I mean, a couple might need you know, modest pipelines, but that's kind of the goal is it just extends the life of infrastructure fullness, if you like, as well.

Okay. And then just on the LNG, like clearly, you know, that's giving you guys a premium pricing. Is there a long-term target of how much production do you want going and selling at LNG prices or even into the California market?

Yeah, we'd like to continue, you know, working the LNG front and I'd expect over the next two or three years, you know, hopefully we enter another couple of contracts. You know, in aggregate, Brian and I are comfortable, you know, in that, you know, 200 or a little bit more million per day range. Okay. Of new additions. Yeah.

Of new additions. Okay. And what's some of the just like the biggest hurdles to getting there? Is it egress? Is it just new projects? you know, takeoffs, you know, on the Gulf Coast? Or are you just kind of waiting for LNG Canada here to come on?

Well, we're looking at everything. And I think, you know, on the marketing side, we're, you know, historically quite creative. But we want to get the best pricing and deal for shareholders, not just do another LNG deal to say we did.

Okay. Thanks, Mike.

Thank you.

Thank you. Ladies and gentlemen, as a reminder, should you have any questions, please press star 1. Next question comes from Joseph Schachter at Schachter Research. Please go ahead.

Good morning, and congratulations on the great quarter. Question, when do you see LNG Canada realizing the amount of production they have and realize what they need to buy in the market, and when do you see contracting as likely to to book $500 million, $600 million a day that they'll need, if that's the number, to meet their production goal of the 2.1 BCF for the initial phase of LNG Canada.

Well, we do think, and I think you're alluding to that, Joseph, that it's going to be positive for Western Canadian basin pricing at both ACO and Station 2. because you're going to pull a significant volume west out of a basin that is more or less currently in supply-demand balance. So, I mean, everything we read publicly and we rely on the same information that you do, it looks like it's starting up likely in the second half of 2025. So, we see that starting to have a positive impact at that point. And, you know, it's really up to the participants in LNG Canada where they source their supply. We kind of see your numbers as about right that, you know, it appears that about 1.4 bees a day is there now. And that likely, the majority of that likely gets pulled west. And it's why tourmaline, our very large North Montney development, which isn't connected to LNG Canada,

you know, higher pricing than we have right now.

Is that helpful?

Yes, it is. One more. Do you think pricing will be off ACO or let's say a premium to ACO, or is there going to be some kind of a JKM format for pricing for takeaway capacity on the West Coast? How do you see the – and where do you see the pricing formula being created?

This is Jamie speaking. You've seen examples of both. It's Termaline's objective to diversify our price, so we're more interested in destination link pricing, but really it's up to each equity partner's discretion on what they're able to offer and how they're able to structure it, and we're willing to be creative and think about things that are derivatives of or links to destination markets, but we don't really need to do ACO link deals because we can do those in many different fashions at home.

That helps out. Thanks very much. Yeah, thank you.

Thank you. Next question comes from Cam Bean at Scotiabank. Please go ahead.

Hi, guys. Congratulations on the quarter. I was just wondering if you could maybe comment a little bit on the additional storage capacity you picked up in California and how you kind of see adding storage capacity into your portfolio going forward.

Hi, Cam. It's Jamie speaking. So we did add some storage in Goose in California, and California has consistently over the last several years proven to be a very, very volatile market, which makes storage very attractive for us there. And being a physical shipper into the state, we've got a firm grasp on the dynamics, and so it seemed prudent to just add a little bit of capacity there. We see this market as a market that's able to add meaningful revenue and meaningful cash flow through storage in both summer and winter. You can have pretty meaningful price spikes in both seasons, and storage has been a nice value accretor in recent history, and we expect it to be a pretty meaningful add in the outlook. And the way you can kind of think of it is we're going to be injecting in the spring and early summer, and we'll be pulling this out in the winter, but we do obviously retain the flexibility to snag as many of these spikes as we can when the system is able to be drafted or packed.

Great. Thanks. Thank you.

Thank you. Next question comes from Michael Harvey at RBC Capital Markets. Please go ahead.

Yeah, sure. Good morning, everybody. Just wanted to ask you about your marketing gains for the quarter. Big gain this quarter, kind of $500 million or so, and that was obviously a big contributor to your free cash flow and then the dividend. That's probably going to move around quite a bit and just be pretty lumpy quarter to quarter. So just curious how you think about that in context of the specials. So Is it better to have a more consistent special paid out at a lower rate, or is it just kind of more of a whatever's left at the end of the quarter type of equation? But just any broad thoughts on those specific marketing gains would be good.

I'm sure it's Brian. So obviously there's a realized and an unrealized component to that. And when we're working through our thinking on the special, we clearly keep our eye on the main prize, which is the cash flow itself. So... to the extent that there's realization on in the money hedges, that's a component of that cash flow and then the unrealized piece we would set aside.

Great. Thanks.

Thank you. Next question comes from Patrick O'Rourke at ATB Capital Markets. Please go ahead.

Hey, guys. Good morning. Congratulations on another strong quarter there. I'm just kind of curious in terms of short-term, capital allocation here and the balance between gassy targets and maybe other targets within the portfolio where the economics are more dictated by liquids. What sort of flexibility or even appetite you have, you know, considering the long-term goals, it sounds like you're long-term constructive on gas and you've got a lot of, you know, strategic gas marketing, storage, all of those things that you put in place. Just to go back to that, would there be any sort of desire to reallocate capital towards more liquids-rich targets?

We kind of do that anyway and have for the past three years. So, you know, it's not a lot every year, but the growth capital that's in the EP plan, the vast majority, you know, is dedicated to northeast BC montane, which is more liquid-rich than the Alberta Deep Basin. it's been more or less on maintenance. Now, it is growing a little bit, and we're kind of in that 255,000 BUEs per day in the Alberta Deep Basin, but the BC Modney is now at 250,000 BUEs a day, so it's essentially caught the Deep Basin from a total production standpoint, because that's where the growth capital has been allocated. We're not toggling or changing the 2023 plan right now. We do get, you know, a bit of an EP breezer if you like during Q2 because of breakup. And so, you know, we've dialed back on the drilling completion activity. So, you know, we look at the gas price and, you know, do we need to do any changes to the program? It's a pretty modest amount of growth that's in there. We're certainly not increasing it, but we'll see, you know, what the strip looks like. And there are some you know, positive nuggets of information evolving on the gas side that, you know, might actually make 2024 more attractive than it looks right now.

Okay. And then within that liquid stream, one thing that caught me in the updated presentation is that it seems as though the quality of the liquid stream is improving a little bit here in 2023. And by that, I mean, the actual oil and condensate, the high value liquids have gone up as a percentage of the overall liquids portfolio. How do you see that trending over time for the business here?

Well, that will continue to happen, especially as we develop the North Montney, which is our most condensate-rich asset as it stands now. And to be fair, within the Alberta Deep Basin, you know, we do try and find the more liquid-rich horizons, but it's not a you know, a major material change to the program. And our ethane is kind of fixed. The ethane we recover is in the Saturn deep cuts, Pemina's two deep cuts in the deep basin. So, you know, that as a percentage will continue to drop because there's no other area that we can recover ethane.

Just remember, Patrick, that because of the north wind disruption, we do recover a little bit less propane and butane in 2023, and that's concentrated on the corner behind us. So that's going to normalize a little bit going forward.

Okay, thank you very much. Yeah, thanks.

Thank you. Next question comes from Jamie Kubik at CIBC. Please go ahead.

Yeah, good morning, and thanks for taking my question. Answered a little bit with what Patrick was asking there, but, you know, the fact that Surmaline did maintain its production capital spending guidance for 2023, we are headed into – Shoulder season with natural gas inventories sitting at historically high levels right now. How should we think about the second half program, depending on where gas prices go over the summer here?

Well, we retain the right to perhaps reduce it. I think I already indicated we're not increasing it. But do bear in mind we're well protected. We're almost 60% hedged in our summer ACO positions. And, you know, the storage situation, obviously, it's pretty full in the U.S. Southeast, but, you know, California is kind of at the opposite end of the spectrum. They're well below historical averages. So, you know, that will help support prices there. And to some extent, you know, the Western Canadian sedimentary basin gets drawn on to help repair the storage situation in California. But, Jamie, anything you want to add to that? I think you're also going to see

some pretty resilient demand. You know, you're seeing that already this spring. You've seen, you know, really robust power burn, especially in the months of March and in April, and we'll see how May treats us here. In any event of a normal to hot summer, that'll be really, really supportive. And also, we are also looking at, you know, activity to the south starting to roll, capital rolling, you know, fracked deferral, rigs coming off probably starting in the next couple months here a little bit more meaningfully. So, These all bend into how we see supply framing up into the winter. And then looking into 2024, that year is looking more and more interesting with additional demand sources coming online and supply probably a little bit more tepid than would have been expected six months ago.

Okay, fair points. And then maybe the second question here from me is just the free cash flow allocation step up to 100% to shareholders in 2023. Okay. primarily through dividends, both base and special. Can you talk a little bit about how you might look at the NCIB and perhaps the M&A side of things here as well, just given where pricing has gone to and how you guys are thinking about that?

On the NCIB, we'll be there in a defensive mode and a strategic mode, which is how we've always communicated that, so we won't go... with a large programmatic buyback. But, you know, we are always looking at that. And it is, you know, an important viable use of free cash flow. And similarly, we're always looking at M&A opportunities. And, you know, we're talking about weak gas pricing in the second half of 2023 or Q2 as well, for that matter. And, you know, will that potentially create some M&A opportunities? You know, it could well. And that's what we think We can make very good investments on behalf of shareholders. We have very strict criteria on when we execute on M&A, and opportunities may arise in the second half.

Okay, that's it for me. Thank you. Yeah, thank you.

Thank you. Next question comes from Mike Dunn at Stifel. Please go ahead.

Thanks for taking my question. You gentlemen have touched on it in a couple of different points already, but I was going to ask about your thoughts on the, I guess, the California or Western U.S. gas market this year versus last year. Storage is low, as you said. It was a wet winter, so perhaps the hydroelectric might be in better shape. But you gentlemen are more experts than I am on that market, so maybe just your thoughts of how it might be shaping up different if at all this year versus last year. Thank you.

Yeah, so it is a different year, but it's a very, very tight year. So we do see higher snowpack that does allow hydro to participate a little bit more. That's actually more of a Southern California feature. Pack Northwest, so we're selling the exposure in Oregon, is not as heavy as snowpack. And so we're seeing a gas demand grind there. pretty modest, call it 100 to 200 million a day grind. But as Mike was saying, storage is so, so low in the state that it's going to take them a full year of healing to kind of renormalize their and allow themselves a bit more of a headroom to survive another winter, especially if another winter comes in as severe as the last one did. The other thing we continue to observe is the install rates on solar and wind in the state continue to be pretty robust. but they're self-curtailing. Much of the solar that's being installed today is actually pushing and competing with solar that was installed over the last decade in the middle of the day, and it's doing nothing to help serve the demand needs in the evening. And so gas demand in that evening part of the day continues to be robust, and that's going to be very supportive through the summer here, especially as we heat up. As we were mentioning before, California is a unique market in that you can have really, really big tightness and severe grid constraint in both summer and winter. And so if you see a hot spell through August, we could see some really, really popped and high gas prices, just like you would normally see in a constrained market in the winter. And then lastly, there's been no incremental pipeline or additional gas supply into state. The state is kind of using the exact same gas supply it has been using roughly for the last five years. Meanwhile, generation needs and demand needs grow year over year over year. And that evening load and that base load is a bit underserved here. And so GATT is answering much of that call, and that's why it's such a strong market.

Thanks, Jamie. That's helpful. That's all from me.

Thanks. Thank you. And the next question comes from Faye Lee at Outland Brown. Please go ahead.

Hi, it's Faye here. Thank you. Mike, I just mentioned about the share buybacks and looking at it from a defensive standpoint. there's been a decent pullback in your share price. Would you say that you're getting closer to considering that share buybacks? Or did the board have a certain share price in mind that says, okay, we get here, we'll implement it, we'll switch? How should we be thinking about that?

Well, I mean, yeah, it has pulled back. That's true. And so, yes, I guess logically you would be getting closer to, you know, where we would execute on the the NCIB, and yes, we do have various price levels based on various parameters where we think that might be the right time, but we don't discuss those prices publicly for all kinds of reasons.

No, fair enough. Okay. I just wanted to understand how that worked.

Thanks. Oh, that's great, Fai. Thanks.

Thank you. There are no further questions. I will now turn the call back over to Jamie Hurd for closing comments.

Thank you, Operator, and thank you, everyone, for joining us on the call today. We hope you have a great rest of your day.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.