Tourmaline Oil Q1 2023 Earnings Call Transcript

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May 4, 2023

There are 13 speakers on the call.

Operator

Good morning, ladies and gentlemen, and welcome to the Tourmaline 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. On your touchtone phone. This call is being recorded on Thursday, May 4, 2023.

Operator

I I would now like to turn the conference over to Jamie Hurd, Manager of Capital Markets. Please go ahead.

Speaker 1

Thank you, operator, and welcome everyone to our discussion of Tourmaline's results for 3 months ending March 31, 2023, 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 on Tourmaline annual information form and our MD and 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 Robertson, Vice President of Science and Chief Financial Officer.

Speaker 1

We will start by speaking to some of the highlights of the last quarter and our year so far. After Mike's remarks, we will be open for questions. Mike, please go ahead.

Speaker 2

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.

Speaker 2

1st quarter cash flow was $1,127,000,000 or $3.28 per diluted share. We generated free cash flow of $525,000,000 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 Q1 'twenty three average production of 500 26,000 BOEs a day. We continue to expect full year 'twenty three free cash flow of 2,000,000,000 and our March 31 net debt was $709,000,000 or approximately 0.2 times 2023 full year forecast cash flow of 3,900,000,000. Touching on production, as mentioned, 1st quarter averaged 526,000 BOEs a day with liquids production of a little over 114,000 barrels per day And that's despite the Pembina NGL pipeline system interruption, which reduced production by 8,000 BOEs a day for approximately six current total oil and liquids production has recovered to the 118,000 to 123,000 barrel per day range over the past month.

Speaker 2

Q2 2023 average production range of between 500,000,515,000 BOE per day is currently expected as we begin our injection season into our storage reservoirs and we execute our Q2 planned maintenance programs for both own account and third party. Encouragingly, the April production average has rolled up to approximately 531,000 BOEs 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 2023 average production guidance between 520,000,540,000 BOEs per day remains unchanged. Looking at financial results, as mentioned, Q1 cash flow was $1,130,000,000 on total CapEx of 595,000,000 generating free cash flow of $525,000,000 In 2023 at strip pricing as of April 14, the company continues to expect to generate cash flow of $3,900,000,000 or $11.22 per diluted share And free cash flow of $2,000,000,000 or $5.80 per diluted share on unchanged EP spending of 1,700,000,000 That forecast 'twenty three 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, 'twenty four cash flow has actually improved 3% since our last forecast update.

Speaker 2

Given that strong free cash flow generation outlook for 2023, the company has 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 point $50 per share on May 19, 23 to shareholders of record on May 11. Looking at marketing, Our average realized natgas price was $6.18 per Mcf Canadian in Q1, Significantly higher than the Ayco 5a benchmark price of $3.28 per Mcf Canadian for the period. We have an average of $801,000,000 per day hedged at a weighted average fixed price of $5.58 per Mcf, an average of $137,000,000 per day hedged at a basis to NYMEX of $0.46 per Mcf And an average of $731,000,000 of unhedged volumes exposed to export markets in 2023. And of that $731,000,000 71 percent is exposed to the premium markets such as the U. S.

Speaker 2

Gulf Coast, JKM, Malint, PG and E and We commenced delivery Jan 1 of our $140,000,000 a day to the Cheniere Sabine Pass 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 14 was still $14.87 per CF. And we also have $31,000,000 a day hedged at a weighted average fixed JKM price of $31.26 per Mcf U. S.

Speaker 2

In 2023. And importantly, as of April 1 this year, we were able to increase our natural gas volumes exported to Western U. S. Markets by $100,000,000 per day to a total of $445,000,000 per day through the completion of the West Gate Expansion Project. A few comments on the E and P program.

Speaker 2

We operated maximum 15 drilling rigs during Q1. We're currently operating 4 rigs, 3 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 DUCs entering Q2. So a little higher on the DUC front an incremental 82 permits thus far in 2023, which is certainly a positive development. A little bit of an expiration update.

Speaker 2

As of year end 2022, we have made 15 new pool or new zone discoveries since starting the exploration program well over 3 years ago. And in our year end 2022 reserve report, we booked 1.26 Tcf equivalent from those new pools. And current mapping of these pools indicates we have a potential for 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 3 additional new pool discoveries so far in 2023 that are outside that reserve report. And as of year end 2022, this program has added an estimated 749 Tier 1 and Tier 2 drilling locations, which get added to our existing deep inventories.

Speaker 2

On environmental performance improvement or what we like to call EPI, looking at our diesel displacement efforts between July of 2017 and the end of this Q1, we've now displaced 106,500,000 liters of diesel in our drilling and completion ops, resulting in a net cost savings of 103,000,000 And that includes the cost of the replacement nat gas. And then on April 18 this year, we announced the next step in the diesel displacement initiative. Tourmaline and Clean Energy Fuels Corp we'll 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 we will be happy to take the questions we will be pleased to take questions you may have.

Operator

Thank you. Ladies and gentlemen, we will now begin the question and answer session. First question comes from Jeremy MacRae at Raymond James. Please go ahead.

Speaker 3

Hi, Mike. I just wanted to talk about some high level Strategic questions here. Just on your exploration plays, as any of the results kind of built into your 5 year plan, is this all in the Montney? Can you give us any indication if there's how big this really could be relative to where your current production is here today?

Speaker 2

Well, we think it's material already from a reserve adding an inventory standpoint. I think in the commentary over the past 18 months, we have set up those 15 that are in the year end 2022 report. 3 we think are material and there's 1 in BC and 1 in the Deep Basin just to give you a sense of Geography. And yes, they're material to what we're doing, and they do get rolled into the inventory and in some cases Into the shorter term 5 year plan.

Speaker 3

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

Speaker 2

Well, we do like to look at the whole section, especially with 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 Modest pipelines, but that's kind of the goal is it just extends the life of infrastructure fullness, if you like, as well.

Speaker 3

Okay. And then just on the LNG, like clearly, 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?

Speaker 2

Yes, we'd like to continue working the LNG front and I'd expect over the next 2 or 3 years, hopefully, we enter another couple of contracts. In aggregate, Brian and I are comfortable in that $200,000,000 or a little bit more $1,000,000 per day range. Okay. New additions, yes.

Speaker 3

New additions, okay. And what's some of the just like the biggest hurdles to getting there? Is it egress? Is it just new We'll take off on the Gulf Coast or are you just kind of waiting for LNG Canada here to come on?

Speaker 2

Well, we're looking at everything and I You know on the marketing side, we're 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.

Speaker 3

Okay. Thanks, Mike.

Speaker 2

Thank you.

Operator

Thank you. Next question comes from Joseph Schachter I'm at Schachter Research. Please go ahead.

Speaker 4

Good morning and congratulations on a 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 book $500,000,000 $600,000,000 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.

Speaker 2

Well, we do think and I think you're alluding to that, Joseph, that it's going to be 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 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 it appears that about 1.4 Bs a day is there now and that likely the majority of that likely gets pulled west.

Speaker 2

And it's why Tourmaline, our very large North Montney development which isn't connected to LNG higher pricing than we have right now. Is that helpful?

Speaker 4

Yes, it is. One more. Do you think pricing will be off AECO or let's say a premium to AECO or is there going to be some kind of a JKM

Speaker 1

This is Jamie speaking. You've seen examples of both. It's Tourmaline's objective to diversify our price, so we're more interested in destination linked 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 AECO linked deals because we can do those in many different fashions at home.

Speaker 4

That helps out. Thanks very much.

Speaker 1

Yes. Thank you.

Operator

Thank you. Your next question comes from

Speaker 5

Cam Wondering if you could maybe comment a little bit on the additional storage capacity you picked up in California and how How you kind of see adding storage capacity into your portfolio going forward?

Speaker 1

Hi, Kev. 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.

Speaker 1

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 full 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.

Speaker 6

Great. Thanks. Thank you.

Operator

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

Speaker 7

Yes, sure. Good morning, everybody. Just wanted to ask you about your marketing gains for the quarter. Big gain this quarter, kind of $500,000,000 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.

Speaker 7

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

Speaker 3

is it just kind of

Speaker 7

more of a whatever is left at the end of the quarter type of equation? But just any broad thoughts on those Specific marketing gains would be good.

Speaker 6

Sure. It's Brian. So obviously, there's a realized and an unrealized According 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 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.

Operator

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

Speaker 8

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

Speaker 2

We kind of do that anyway and have for the past 3 years. So the it's not a lot every year, but the growth capital that's in the EP plan, the vast majority It is dedicated to Northeast BC Montney, which is more liquid rich than the Alberta Deep Basin. It's been more or less on maintenance. Now It's growing a little bit and we're kind of in that 255,000 BOEs per day in the Alberta Deep Basin. But the BC Montney is now at 250,000 So it's essentially caught the Deep Basin from a total production standpoint because that's where the growth capital has been allocated.

Speaker 2

We're not toggling or changing the 2023 plan right now. We do get a bit of an EP breather if you like during Q2 Because of breakup, and so we've dialed back on the drilling completion activity. So we look at the gas price and do we need to do any changes to the program. It's pretty Modest amount of growth that's in there. We're certainly not increasing it, but we'll see what the strip looks like.

Speaker 2

And there are some Positive nuggets of information evolving on the gas side that might actually make 2024 More attractive than it looks right now.

Speaker 8

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.

Speaker 2

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, we do try and find a more liquids rich horizons, but it's not A major material change to the program and our ethane is kind of fixed. The ethane we recover is in the Saturn deep cuts, Pembina's 2 deep cuts in the Deep Basin. So that as a percentage will continue to drop because there's no other area that we can recover ethane.

Speaker 1

Remember, Patrick, that because of the Northline disruption, we do recover a little bit less propane and butane in 2023, And that's concentrated on the quarter behind us. So that's going to normalize a little bit going forward.

Speaker 8

Okay. Thank you very much.

Speaker 2

Yes, thanks.

Operator

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

Speaker 9

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

Speaker 2

Well, we retain the right perhaps to 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 AECO position. And the storage situation, obviously, it's pretty full in the U. S.

Speaker 2

Southeast, but California it's kind of at the opposite end of the spectrum. They're well below historical averages. So they'll that will help support prices there. And To some extent, 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?

Speaker 1

I think you're also going to see some pretty resilient demand. You're seeing that already this spring. You've seen 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 normal to hot summer, that will be really, really supportive. And also, we are also looking at activity to the South starting to roll, Capital rolling, frac deferral, rigs coming off probably starting in the next couple of months here a little bit more meaningfully.

Speaker 1

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 CapEx than would have been expected 6 months ago.

Speaker 9

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

Speaker 2

On the NCIB, we'll be there in a defensive mode, which is And a strategic mode, which is how we've always communicated that. So we won't go with a large programmatic buyback, but we are Always looking at that and it is an important viable use of free cash flow. And similarly, we're always looking at M and A opportunities. We're talking about weak gas pricing in the second half of twenty twenty three or Q2 as well for that matter. And will that potentially create some M and A opportunities?

Speaker 2

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 and A And opportunities may arise in the second half.

Speaker 9

Okay. That's it for me. Thank you.

Speaker 2

Yes. Thank you.

Operator

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

Speaker 10

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.

Speaker 10

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.

Speaker 1

Yes. 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 it's a little bit more. That's actually more of a Southern California feature. PAC Northwest, so we're selling exposure in Oregon is not as heavy as Snowpack.

Speaker 1

And so we're seeing gas demand grind there Pretty modest, call it $100,000,000 to $200,000,000 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 there's

Speaker 11

still a lot of work that we're

Speaker 1

doing and allow themselves a bit more of a headroom to survive another winter, especially if another winter comes in That's 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 and 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 pop in high gas prices, just like you would normally see in a constrained market in the winter.

Speaker 1

And then lastly, there's been no incremental pipeline or additional gas The state is kind of using the exact same gas supply, which has been using roughly for the last 5 years. Meanwhile, generation needs and demand needs grow year over year over year and that evening load and that baseload Is a bit underserved here and so gas is answering much of that call and that's why it's such a strong market.

Speaker 10

Thanks, Jamie. That's helpful. That's all for

Speaker 11

me. Thanks.

Operator

Thank you. And the next question comes from Fai Lee at Othland Brown. Please go ahead.

Speaker 12

Hi, it's Fai 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 does the Board have a certain share price in mind that says, okay, we get here, we'll implement it, we'll switch or how should we be thinking about that?

Speaker 2

Well, I mean, it has pulled back. That's true. And so yes, I guess, logically, you would be getting closer to where we would execute on 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.

Speaker 12

No, fair enough. Okay. I just want to understand how that works. Thanks.

Speaker 2

That's great, Phil. Thanks.

Operator

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

Speaker 1

Thank Thank you, operator, and thank you, everyone, for joining us on the call today. We hope

Speaker 11

you have a great rest of your day.

Operator

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

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