Good morning, ladies and gentlemen. 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. To ask a question, please press star one on your touchtone phone. If at any time during this call you need assistance, please press star zero for the operator. This call is being recorded on Thursday, May 4th, 2023. I will now like to turn the conference over to Jamie Heard, Manager of Capital Markets. Please go ahead.
Thank you, operator, welcome everyone to our discussion of Tourmaline's results for the three months ending March 31st, 2023 and 2022. My name is Jamie Heard, 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 form and our MD&A available on SEDAR in 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, Brian Robinson, 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. Welcome everyone. Good morning. We're pleased to review Tourmaline's Q1 results and answer questions you may have. 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. That allowed us to declare a special dividend of $1.50 per common share. We had record first quarter 2023 average production of 526,000 BOEs a day. We continue to expect full year 2023 free cash flow of $2 billion. Our March 31 net debt was $709 million or approximately 0.2x 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. That's despite the Pembina 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 118,000-123,000 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 BOEs per day, which is a record, and that is prior to storage injections, which have happened in the month as well. Our full year 2023 average production guidance of between 520,000 and 540,000 BOEs per day remains unchanged. Looking at financial results, as mentioned, first quarter cash flow was CAD 1.13 billion on total CapEx of CAD 595 million, generating free cash flow of CAD 525 million.
In 23 at strip pricing as of April 14th, the company continues to expect to generate cash flow of CAD 3.9 billion or CAD 11.22 per diluted share and free cash flow of CAD 2 billion or CAD 5.80 per diluted share on unchanged EP spending of CAD 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. 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 2023, the company's elected to increase the quarterly base dividend, effective this quarter to CAD 1.04 per share on an annualized basis from the current annualized CAD 1.00 per share. As well, declare and pay a special dividend of CAD 1.50 per share on May 19, 2023 to shareholders of record on May 11. Looking at marketing, our average realized Nat gas price was CAD 6.18 per Mcf in Q1, significantly higher than the AECO 5A benchmark price of CAD 3.28 per Mcf for the period. We have an average of 801 million per day hedged at a weighted average fixed price of CAD 5.58 per Mcf.
An average of 137 million per day hedged at a basis to NYMEX of $0.46 per Mcf U.S. and an average of 731 million of unhedged volumes exposed to export markets in 2023. Of that 731 million, 71% is exposed to the premium markets such as, you know, the U.S. Gulf Coast, JKM, Malin, PG&E and Sumas. We commenced delivery January 1 of our 140 million 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 2023 JKM strip price, as of April 14, was still $14.87 per Mcf U.S.
We also have 31 million a day hedged at a weighted average fixed JKM price of $31.26 per Mcf in 2023. Importantly, as of April 1 of this year, we were able to increase our natural gas volumes exported to Western U.S. markets by 100 million per day to a total of 445 million per day through the completion of the West Gate 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 DUCs entering Q2.
A little higher on the DUC front than past years. Importantly, Tourmaline has 388 valid drilling permits in Northeast BC now, having received an incremental 82 permits, thus far in 2023, which is certainly a positive development. A little bit of an exploration update. As of year-end 2022, we have made 15 new pool or new zone discoveries since starting the exploration program, well over three years ago. In our year-end 2022, reserve report, we booked 1.26 Tcf equivalent from those new pools. Current mapping of these pools, indicates the potential for a further 3.2 Tcf of raw natural gas that we'll delineate with follow-up drilling, over the next couple of years.
We also have made three additional new pool discoveries so far in 2023 that are outside that reserve report. As of year-end 2022, this program's added an estimated 749 tier one and tier two 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 2017 and the end of this first quarter, we've now displaced 106.5 million liters of diesel in our drilling and completion ops, resulting in a net cost savings of CAD 103 million, and that includes the cost of the replacement nat gas. 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. The initiative allows for the use of readily available natural gas to significantly lower emissions from heavy-duty trucks and other commercial transportation fleets. There's lots of long-term upside to this initiative, both for emissions reduction and for building natural gas demand. That's the end of kind of the formal remarks. 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 touch-tone phone. If you would like to withdraw your request, please press star followed by two. If you are using a speakerphone, please lift the handset before pressing any keys. First question comes from Jeremy McCrea at Raymond James. Please go ahead.
Yeah, hi, Mike. I just wanted to talk about some high-level strategic questions here. Just on your exploration plays, has any of the results kind of built into your five-year plan, is this all in the Montney? Can you give us any indication, 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 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 22 report. three, we think are material, there's one in BC and one in the Deep Basin, just to give you a sense of geography. 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. Montney, I'm guessing, in BC, or is it other formations that you guys are looking at here too?
We do like to look at the whole section, especially with, when we're, you know, talking exploration. 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. 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.
And like c ontinue, you know, working the LNG front. 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. What's some of the just like the biggest hurdles to getting there? Is it egress? Is it just new?
You know, with 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 one. Next question comes from Josef 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? When do you see contracting as likely to book 500-600 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, Josef, that it's gonna be positive for western Canadian basin pricing at both AECO and Station 2, because you're gonna pull a significant volume west out of a basin that is more or less currently in supply demand balance. I mean, everything we read publicly and, you know, we rely on the same information that you do. It looks like it's starting up, you know, likely in the second half of 2025. You know, we see that starting to have a positive impact at that point. You know, it's really up to the participants in LNG Canada, where they source their supply.
We kinda see your numbers as about right, that, you know, it appears that about 1.4 BCF a day is there now. That likely the majority of that likely gets pulled west. It's why Tourmaline, our very large North Montney development, which isn't connected to LNG. You know, higher pricing than we have right now. Is that helpful?
Yes, it is. One more. Do you think pricing will be off AECO or let's say a premium to AECO? Is there gonna 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 Tourmaline's objective to diversify our price. We're more interested in destination-linked pricing. 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. We're willing to be creative and think about things that, you know, are derivatives of or links to destination markets. We don't really need to do AECO 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 Cameron 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. 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. 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 creator in recent history, and we expect it to be a pretty full meaningful add in the outlook.
The way you can kinda think of it is we're gonna be injecting in the spring and early summer, and we'll be pulling this out in the winter. We do obviously retain the flexibility to snag as many of these spikes as we can when the system's 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 CAD 500 million or so, and that was obviously a big contributor to your free cash flow and then the dividend. That's probably gonna move around quite a bit and just be pretty lumpy quarter to quarter. Just curious how you think about that in context of the specials. 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? Just any broad thoughts on those specific marketing gains would be good.
I'm sure it's Brian. Obviously there's a realized and an unrealized component to that. 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. 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. Just kinda 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 your long-term constructive on gas and you've got a lot of, you know, strategic gas marketing storage, all of those things that you've 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 kinda do that anyway and have for the past three years. The, 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 Montney, 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 BOEs per day in the Alberta Deep Basin. The BC Montney is now at 250,000 BOEs a day, so it's essentially caught the Deep Basin, from a total production standpoint, because that's where the growth capital's been allocated. We're not toggling or changing the 2023 plan right now.
We do get, you know, a bit of an EP breather, if you like, during Q2, because of breakup. You know, we've dialed back on the drilling completion activity. You know, we look at the gas price and, you know, 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, you know, what the strip looks like. 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. 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. By that I mean the actual oil and condensate, the high value liquids have gone up as a % of the overall liquids portfolio. How do you see that trending over time for the business here?
That will continue to happen, especially as we develop the North Montney, which is our most condensate rich asset as it stands now. To be fair, within the Alberta Deep Basin, you know, we do try and find more liquids rich horizons, but it's not a, you know, a major material change to the program. Our ethane is kind of fixed. The ethane we recover is in the Saturn deep cuts, Pembina's two deep cuts in the Deep Basin. 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 Line 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 gonna 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 Cenovus 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 where gas prices go over the summer here?
Well, we retain the right to, you know, perhaps reduce it. I think I already indicated we're not increasing it. Do bear in mind, you know, we're well protected. We're almost 60% hedged in our summer AECO position. 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. You know, they'll that will help support prices there. To some extent, you know, the Western Canadian Sedimentary Basin gets drawn on to help repair the storage situation in California. Jamie, anything you wanna add to that?
I think you're also gonna 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. Also, we are also looking at, you know, activity to the south starting to roll, capital rolling, you know, frack deferral, rigs coming off probably starting in the next couple months here a little bit more meaningfully. These all bend into how we see supply framing up into the winter. 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've been expected 6 months ago.
Okay. Fair points. Then maybe second question here from me is just the free cash flow allocation step up to 100% to shareholders in 2023, 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 is going too and how you guys are thinking about that?
On the NCIB, we'll be there in a defensive mode, which is in a strategic mode, which is how we've always communicated that. We won't go with a large programmatic buyback. You know, we are always looking at that, and it is, you know, an important viable use of free cash flow. 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. 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, you know, 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. 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. You gentlemen are more experts than I am on that market. Maybe just your thoughts of how it might be shaping up different if at all, this year versus last year. Thank you.
It is a different year, but it's a very, very tight year. We do see higher snowpack that does allow hydro to participate a little bit more. That's actually more of a Southern California feature. Pac Northwest, so we're selling the export exposure in Oregon, is not as, you know, as heavy a snowpack. We're seeing, you know, a gas demand grind there, pretty modest, call it 100 million-200 million a day grind. As Mike Rose was saying, storage is so low in the state that it's gonna take them a full year of healing to kinda re-normalize 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. It's doing nothing to help serve the demand needs in the evening. Gas demand in that evening part of the day continues to be robust, and that's gonna 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 big tightness and severe grid constraint in both summer and winter.
If you see a hot spell through August, we could see some really, really pop, you know, pop and high, high gas prices just like you would normally see in a constrained market in the winter. Lastly, there's been no incremental, you know, 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. Gas 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. The next question comes from Fai Lee at Odlum Brown. Please go ahead.
Hi, it's Fai here. Thank you. Mike, I just, you 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?
Well, I mean, yeah, it has pulled back, that's true. Yes, I guess logically, you would be getting closer to, you know, where we would execute on the NCIB. Yes, we do have, you know, various price levels based on various parameters where we think that might be the right time. We, you know, we don't discuss those prices publicly for all kinds of reasons.
Okay. No, fair enough. Okay, I just wanted to understand how that worked. Thanks.
No, that's great, Fai. Thanks.
Thank you. There are no further questions. I will now turn the call back over to Jamie Heard 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.