Tourmaline Oil Corp. Q1 2023 Earnings Call
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Good morning, ladies and gentlemen, and welcome to the Tremor line 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 op.
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This call is being recorded on Thursday may 4th 2023, I would now like to turn the conference over to Jamie <unk> manage our capital markets. Please go ahead.
Thank you operator, and welcome everyone to our discussion of <unk> results for three months ending March 31, 2023, and 2022. My name is Jamie heard my interim lease 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 environment Advisory is contained on the terms.
The 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 Micros, Trillanes, President and Chief Executive Officer, and Brian Robertson, Vice President 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 will be opened for questions. Mike. Please go.
Thanks, Jamie.
Welcome everyone. Good morning.
I'm pleased to review <unk> Q1 results and answer questions. You may have so firstly some highlights first.
First quarter cash flow was $1, one $2 7 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 'twenty three average production of 526000 BOE 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 <unk> two times 2023 full year forecast.
Cash flow of $3 9 billion.
Touching on production.
As mentioned first quarter averaged 526000 BOE a day.
Liquids production, a little over 114000 barrels per day.
And that's despite the Pembina NGL pipeline system interruption, which reduced production.
By 8000, Boe's a day for approximately six weeks current total oil and liquids production has recovered to 118 223000 barrel per day range over the past month.
Q2, 'twenty three average production range of between 500000 and 515000 BOE per day is currently expected as.
As we begin our injection season into our storage reservoirs and we execute our Q2 planned maintenance programs Bert bolt, one account and third party.
Encouragingly. The April production average has rolled up to approximately 531000 Boe's 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 'twenty three average production guidance of.
Between 520000, and 540000 Boe's per day.
<unk> is unchanged.
Looking at financial results as mentioned first quarter cash flow was $1. One 3 billion on total capex of $595 million Jenny.
Generating free cash flow was $525 million.
In 'twenty three 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 was actually improved 3%.
Since our last forecast update.
Given that strong free cash flow generation outlook for 'twenty three the company has elected to increase the quarterly base dividend.
<unk> this quarter to $1 four 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 19 to 23 to shareholders of record on May 11th.
Looking at marketing our average realized Nat gas price was $6 18 per Mcf Canadian.
In Q1.
Significantly higher than the equal five eight 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 $5 58 per Mcf Canadian.
An average of 137 million per day hedged at a basis to Nymex of 46 cents per Mcf of U S and an average of $731 million of unhedged volumes exposed to export markets in 'twenty three.
That $731 million, 71% is exposed to the premium markets such as the U S Gulf Coast <unk> animal in <unk> and <unk>.
We commenced delivery.
One of our 140 million a day to the Cheniere Sabine pass LNG facility.
Our average Q1 realized price before liquefaction and shipping fees was $19 44 per Mcf U S.
23, <unk> strip price.
As of April 2014.
What's still a <unk> dollars 87 per Mcf U S. And we also have 31 million a day hedged at a weighted average fixed GTA JJ embrace of $31 26 per Mcf U S. In 2023.
And importantly as of April one 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 Westgate expansion project.
Your comments on the E&P program, we operated a maximum 15 drilling rigs. During Q1 were currently operating four rigs three of them and in BC is we're in breakup we.
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 docks.
Entering Q2, so a little higher almond upfront them than past years.
Importantly, <unk> has 388 valid drilling permits in northeast BC now having received an incremental 82 permits thus far in 'twenty, three which is certainly a positive development.
A little bit of an exploration update as of year end 'twenty. Two we have made 15, new pool or new zone discovery since starting the exploration program well over three years ago.
And in our year end 'twenty two reserve report.
Booked $1 two six tcf equivalent from those new pools and current mapping of these pools indicates the potential for a further three two tcf.
<unk> 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 'twenty three that are outside of that reserve report.
And as of year end 'twenty. Two this programs 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 looked.
Looking at our diesel displacement efforts between July of 17, and the end of this first quarter. We've now displaced $106 5 million liters of diesel in our drilling and completion offs, resulting in a net cost savings of $103 million and that includes the cost of the replay.
<unk> Nat gas.
And then on April 18th of this year, we announced the next step in the diesel displacement initiative Terminalling and clean energy fuels Corp will jointly build and operate a network of up to 20 <unk> stations, along key highway corridors across Western Canada and the initiative.
<unk> for the use of ready readily available natural gas is significantly lower emissions from heavy duty trucks and other commercial transportation fleets and Theres lots of long term upside for this initiative both for emissions reduction.
And for building natural gas demand so that's.
That's the end of kind of our formal remarks. So we will be pleased to take questions. You may have.
Thank you Lee.
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.
I'd like to withdraw your question. Please press star followed by chance.
And if you are using a speaker phone please lift the handset before pressing any case.
First question comes from Jeremy Mccrea at Raymond James. Please go ahead.
Hey, 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 five year plan is this all in the Montney.
Can you give us any indication.
You know if there is how big this really could be relative to where your current production is here today.
Well, we think its 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 'twenty to report three we think are material and Theres, one NBC and one in the deep basin just to give you a sense of a.
Geography.
And yes, there are 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 NBC or is there or is it other formations that you guys are looking at here too.
Well, we do like when you look at the whole section, especially with.
When we're talking exploration. 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 of my need.
Modest pipelines, but that's kind of the goal is it just extends the life of infrastructure fullness, it feels like as well.
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 that LNG prices or even into the California market.
Yeah, we'd like to continue.
Working the LNG front and.
I would expect over the next two or three years hopefully we enter another couple of contract channel.
In aggregate.
Brian and I are comfortable in that 200, or a little bit more million per day range.
Okay and the addition.
From new additions, okay, and what some of the just the biggest hurdles to getting there is it egress is just new.
Yes, it will take off.
On the Gulf Coast or are you just kind of waiting for LNG, Canada care to come on.
Well, we're looking at everything and I think you know on the marketing side.
Historically quite creative but we wanted 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 section Research. Please go ahead.
Good morning, and congratulations on a great quarter.
Question.
When do you see LNG, Canada about realizing the amount of.
Production may happen realized what they need to buy in the market and when do you see contracting is likely.
Two.
$5 600 million a day that they'll need alright, if thats the number.
To meet their production goals of the two one Bcf a day for the initial phase of LNG, Canada.
Well we.
We do think and I think you are alluding to that Joseph that it's going to be.
Positive for Western Canadian Basin pricing at both vehicle and station two because youre going to pull a significant volume west out of a basin that is more or less currently in supply demand balance so.
Everything we read publicly and we rely on the same information that you do it looks like it's starting up.
Lately 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 on LNG, Canada, where they source their supply we kind of see your numbers is about right.
It appears that about 1.4 BS a day is there now and.
And that likely the majority of that likely gets pulled west and it's why it <unk> are very large in north montney.
Development, which isn't connected to LNG, Canada, contractually, but we see that as a good time to bring new supply to market. Because we think we're going to enjoy higher pricing than we have right now is that helpful.
One more do you think pricing will be off a cohort at let's say a premium to equal or is there going to be some kind of a J K M format for pricing for takeaway capacity on the West Coast. How do you how do you see the and where do you see the pricing formula being created.
Yeah. This is Jamie speaking you've seen examples of both.
It's terminals objective to diversify our price. So we're more interested in destination linked pricing, but really it's up to each equity partners discretion on what theyre able to offer and how they're able to structure it and we're willing to be creative and think about things.
Our derivatives or links to destination markets, but we don't really need to do a co link deals because we can do those and many different fashions at home.
Okay that helps thanks very much.
Thank you.
Thank you next question comes from the campaign next 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.
Are you kind of see adding storage capacity into your portfolio going forward.
Our cabinet serious speaking so we did add some storage and goes out in California, and California has consistently over the last several years has proven to be a very very volatile market, which makes storage very attractive for us there and being a physical shepherd with a 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'd see there.
This market is a market that's able to add.
Meaningful revenue and meaningful cash flow through storage and both summer and winter you can have pretty meaningful price spikes in both seasonal and storage has been a nice value accretive.
In recent history, and we expect it to be a pretty full meaningful AD in the outlook and the way you can kind of think of it as we're going to be injecting in the spring and early summer it will be pulling this out in the winter, but we do obviously you've retained the flexibility to snag as many of these spikes as we can.
When the system is able to be drafted are packed.
Great. Thanks.
Thank you.
Thank you. Your 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 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.
Probably going to move around quite a bit and just be pretty lumpy quarter to quarter. So just curious how.
How are you thinking 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 is left at the end of the quarter type of equation, but just any broad thoughts on those specific marketing gains would be it would be good.
I'm sure it's Brian so.
Obviously, theres, a realized and unrealized component to that and when we're working through our thinking on that on the special we clearly keep our eye on the main prize, which is the cash flow itself. So to the extent that there is a realization on in the money hedges.
Part of that cash flow and then the unrealized piece, we would set aside.
Great. Thanks.
Thank you. Your 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 kind of curious in terms of short term.
Capital allocation here in 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.
Considering our long term goals it sounds like your long term.
Constructive on gas and you've got a lot of strategic gas marketing storage all of those things that you've 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.
We kind of do that anyway and have for the past three years. So the you know it's.
It is not a lot every year, but the growth capital that's in the plan.
Fast majority 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 255000 Boe per day in the Alberta deep basin, but the BC Montney is now at 250000 Boe's a day. So it's essentially caught the deep basin.
From a total production standpoint, because thats, where the growth capital has been allocated we're not toggle lean or changing.
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 and completion activity.
So when we look at the gas price and 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 what the strip looks like 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.
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, so the business here.
That will continue to happen, especially as we develop the north Montney, which is our most condensate.
Rich asset as it stand now and to be fair within the Alberta Deep basin, we do.
Try and find the more liquids rich horizons, but it's not out.
A major material change to the program and our ethane is kind of fixed the ethane recoveries in the Saturn deep cuts permanent two deep cuts in the deep basin. So you know.
That as a percentage will continue to drop because theres no other.
The area that we can recover ethane.
Just remember Patrick that because of the Northland disruption, we do recover a little bit less propane and butane in 2023, and thats concentrated on a quarter behind us so that's going to normalize a little bit going forward.
Okay. Thank you very much.
Yes.
Okay.
Thank you. Your next question comes from Jamie Kubik at CIBC. Please go ahead.
Yes, good morning, and thanks for taking my question.
A little bit with what.
Hatrick was asking there but.
The fact that <unk> did maintain its production capital spending guidance for 2023.
We are headed into the 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.
But we retain the right to.
Perhaps reduce it I think I already indicated we're not increasing them, but do bear in mind.
Well protected where almost 60% hedged in our summer Ah <unk> position.
And.
The storage situation, obviously, it's pretty full in the U S southeast, but California is kind of at the opposite end of the spectrum, there well below historical averages so.
Well that that will help support prices, there and to some extent.
Western Canadian sedimentary basin gets drawn on.
To help repair the storage situation in California, but Jamie anything you want to add to that.
Youre also going to see some pretty resilient demand youre 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 a normal to hot summer that'll be really really supportive and also we are also looking at activity to the south starting to roll cap.
Capital Rolling Frac deferral rigs coming off probably starting in the next couple of months here a little bit more meaningfully. So these all bent into how we see supply framing up into the winter and then looking into 2020 for that year is looking more and more interesting with additional demand sources coming online and supply is probably a little.
More tepid than would've been expected six months ago.
Okay Fair point and then maybe second question here for me is just the free cash flow allocation step up to a 100% to shareholders in 2023.
Primarily through dividends both based on special can you talk a little bit about how you might look at the NCI and perhaps.
The M&A side of things here as well just given where.
<unk> is going to and how you guys are thinking about that.
On the NCI NCI will be there in a defensive mode, which is in our strategic moat, which is all we have.
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&A opportunities and we're talking about weak gas pricing in the second half of 2023 or Q2 as well for that matter in.
Will that potentially create some emma.
M&A opportunities you know it could well and Thats, what we think.
We can make very good investments on behalf of our shareholders. We are 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 yes. Thank you.
Thank you next question comes from Mike Dunn at Stifel. Please go ahead.
Thanks for taking my question.
You gentlemen, I've touched on 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 as low as you said it was a wet winter so perhaps the hydro electric.
Might be in better shape, but.
You gentlemen are more experts volume on that market. So.
Maybe just your thoughts of how it might be shaping up differently. If at all this year versus last year. Thank you.
Yeah. So it's it is a different year, but it's a very very tight years. So we do see higher snowpack that does allow hydro to participate a little bit more of that is actually more of a southern California feature Pac northwest. So we're selling the northern California, and we also have some export exposure in Oregon.
Is not as you know as heavier snowpack and so we're seeing.
Gas demand grind, they're 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 is going to take them a full year of helium to kind of re normalize their system and allow themselves a bit more of a of a headroom to survive another winter, especially if another winter it comes in at <unk>.
Here at the last one did the other thing we continue to observe as they 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 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 in severe grid constraint in both summer and winter and so if you see a hot spell through <unk>.
August we could see some really really pop pop in high high gas prices just like you would normally see in a constrained market in the winter and then lastly, there has been no incremental pipeline or additional gas supply into state.
Data is kind of using the exact same gas supply, which has been using roughly for the last five years.
While generation needs and the band needs grow year over year over year and that evening load in that base load is a bit underserved here and so gases is answering much of that call and that's why it's such a strong market.
Thanks, Jamie that's helpful. That's all for me.
Thanks.
Thank you and the next question comes from Daily at Elton Brown. Please go ahead.
Alright, yes satisfy here. Thank you Mike you mentioned about the share buybacks and looking at it from a defensive standpoint.
There's been a decent pull back 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. It says I think we get here, we'll implement it will switch or how should we be thinking about that.
Well I mean, yes. It has pulled back thats true and so yes, I guess logically you would be getting closer to where.
Where we would execute on the NCI and CIB and yes, we do have.
Various price levels based on various parameters, where we think of that might be the right time, but.
We don't discuss those prices publicly for all kinds of reasons.
Fair enough, Okay, I, just want to understand how that works.
No that's great. Thanks.
Thank you there are no further questions I will now turn the call back over to Jamie for closing comments.
Thank you operator, and thank you everyone for joining us on the call today, and we hope you have a great rest of your day.
Yeah.
Ladies and gentlemen, this concludes your conference call for today, we thank you for participating and we ask that you. Please disconnect your lines.