Q4 2023 Tourmaline Oil Corp Earnings Call

Operator: Good day, ladies and gentlemen, and welcome to Tourmaline's 4th Quarter 2023 Results Conference Call. At this time, all lines are in a listen-only mode.

Good day, ladies and gentlemen, and welcome to Terminal Inc. Fourth quarter 2023 results conference call. At this time all lines are in a listen only mode.

Operator: Following the presentation, we will conduct a question-and-answer session. If anyone has any difficulty hearing the conference, please press star zero for operator assistance at any time. I would now like to turn the conference over to Scott Kirker. Please do so.

Following the presentation, we will conduct a question and answer session.

Has any difficulties hearing the conference. Please press star zero for operator assistance at any time.

I'd now like to turn the conference over to Scott Parker. Please go ahead.

Scott Kirker: Thank you, operator, and welcome everyone to our discussion of Tourmaline's results for the years ended December 31, 2023, and December 31, 2022. My name is Scott Kirker, and I'm the Chief Legal Officer here at Tourmaline. Before we get started, I refer you to the advisories on forward-looking statements contained in the news release, as well as the advisories contained in the Tourmaline Annual Information Form and our MD&A, available on CDAR and on 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, our Chief Financial Officer, and Jamie Heard, Tourmaline's Vice President of Capital Markets. We will start by speaking about some of the highlights of the last quarter and our year so far. And after Mike's remarks, we will be open to questions. Go ahead, Mike.

Thank you operator, and welcome everyone to our discussion of <unk> results for the years ended December 31, 2023, and December 31 2022.

My name is Scott Kirker, and I'm, the Chief legal officer here at <unk>.

Before we get started I refer you to the advisories on forward looking statements contained in the news release as well as the advisories contain that Germany and annual information form and in our MD&A available on SEDAR and on our website.

I will draw your attention to the material factors and assumptions and those advisors.

Here with Mike Rose <unk>, President and Chief Executive Officer, Brian Robinson, Our Chief Financial Officer, Jamie her term links Vice President of capital markets. We will start by speaking to some of the highlights of last quarter and our year, So far and after Mike's remarks, we will be open for questions go ahead, Mike. Thanks, Scott Welcome everybody and we're pleased to review our 2012.

Scott Kirker: Thanks, Scott. Welcome, everybody, and we're pleased to review our 2023 results. Here are a few of the highlights.

Q3 results.

Michael L. Rose: Full year, 23 cash flow was $3.71 billion, or $10.73 per diluted share. Fourth quarter, 23 cash flow was $918 million, and it generated $1.69 billion of free cash flow in 2023. Full year earnings were $1.74 billion, a very strong $5.03 per diluted share. We successfully closed the acquisition of Bonavista during the fourth quarter.

A few of the highlights full year 23 cash flow was $3 71 billion or $10 73 per diluted share fourth quarter 23 cash flow was 918 million regenerated 169 billion of free cash flow.

2023.

Full year earnings were $1 74 billion, a very strong five three per diluted share.

We successfully closed the acquisition of Monte Vista during the fourth quarter.

Michael L. Rose: Tourmaline will pay a special dividend of $0.50 per share on March 21, 2024, and we intend to pay special dividends in all four quarters of 2024, and we've also increased the quarterly base dividend by 7% to $1.30 per share. Year-end 23 approved developed producing reserves, or PDP, of 1.2 billion BOEs were up 39.3%. Total approved reserves of 2.61 billion BOEs were up 21%, and 2 fee reserves of 5.01 billion BOEs were up 15.5%. After 15 years of operation, the company has 22.7 TCF of economic 2P natural gas reserves, all of which is pipeline-connected to markets across North America. And at year-end 23, we still only book 16.5% of our extensive drilling investment.

Internally, we will pay a special dividend of <unk> 50 per share on March 21, 2024.

And we intend to pay special dividends in all four quarters of 'twenty four.

And we've also increased the quarterly base dividend by 7% to 30 cents per share.

Year end 'twenty, three proved developed producing reserves or PDP.

$1 2 billion Boe's were up 39 three.

3% total proved reserves of $2 61 billion were up 21% and <unk> reserves of $5 1 billion were up 15, 5%.

After 15 years of operation the company has $22 seven Tcf of economics to be natural gas reserves, all of which is pipeline connected to markets across North America and at year end 'twenty three we still still.

Only blocked 16, 5% of our extensive drilling inventory year.

Michael L. Rose: URN 23-2P Oil Condensate and NGL reserves of 1.22 billion barrels represent the second largest conventional liquids reserve base in Canada based on public information. Given continuing weak natural gas prices this year, we have elected to reduce the forecast 24 capital expenditures from $2.35 billion to $2.13 billion, and we will continue to focus on optimizing free cash flow and shareholder returns. Our fourth quarter, 23 average production was 557,000 BOEs per day, and that was up 9% from the fourth quarter of 22. And full year, 23 average production of a little over 520,000 BOEs per day was up 4% over the full year, 22 average. In calendar 2024, we have an average of 726 million cubic feet per day hedged at a weighted average fixed price of $5.34 per MCF. Montney.

Year end 'twenty, three <unk> oil condensate and NGL reserves of $1 2 billion barrels.

<unk> represents the second largest conventional liquids reserve base.

Canada based on public information.

Given continuing weak natural gas prices. This year, we have elected to reduce the forecast 24 capital expenditures from 235 billion to $2, one 3 billion.

And we will continue to focus on optimizing free cash flow and shareholder returns.

Our fourth quarter 'twenty three our production was.

557000 Boe per day, and that was up 9% from the fourth quarter of 'twenty two.

In full year 'twenty three average production of a little over 520000 Boe's per day was up 4% over the full year 22 average.

In.

Calendar 2024, we have an average of 726 million cubic feet per day hedged at a weighted average fixed price of $5 34 per Mcf.

Michael L. Rose: Well performance in BC continues to improve, with 2023 wells outperforming wells from the previous three years. Both natural gas and, particularly, liquids production are exceeding the previous year's performance. At current strip prices, we expect to generate 24 cash flow of $3.32 billion and free cash flow of approximately $1.2 billion. Looking at production, a couple more stats. With the announced significant 24 capital budget reduction, our 24 average production is now 580,000 to 590,000 BOEs per day, so 585 at the midpoint. And we expect Q1 average production of between 590,000 and 595,000 BOEs per day, as the capital reductions did impact the first quarter. Forecast liquids production of approximately 144,000 barrels per day is actually ahead of the original forecast, and daily liquids production has eclipsed 150,000 barrels per day on several days so far this year. Reiterating a couple of the financial highlights, as mentioned, full year earnings were $5.03 per diluted share.

Might be well performance in BC continues to improve with 23, well 2023 wells outperforming wells from the previous three years.

Both natural gas and particularly liquids production are exceeding the previous year's performance.

At current strip pricing, we expect to generate 24 cash flow of $3 three 2 billion.

And free cash flow of approximately one 2 billion.

Looking at production a couple more stats.

With the announced.

<unk> 2004 capital budget reduction or 24 average production is now 580000 to 590000 Boe's per day sold 585 at the midpoint.

And we expect Q1 average production of between 590 and 595000 Boe's per day.

The capital reduction did impact the first quarter.

Forecast liquids production of approximately 144000 barrels per day is actually ahead of original forecast in daily liquids productions Eclipse the 150000.

Barrels per day on several days so far this year.

Reiterating a couple of the financial highlights as mentioned full year earnings were $5 three per diluted share.

Michael L. Rose: We paid $6.55 per share in combined base and special dividends in 2023, and that's a 10% trailing yield. We have elected to increase the base dividend, as mentioned, by 7% for the first quarter of this year, and we have now increased the base dividend a total of 13 times since we initiated the dividend in the first half of 2018. Exit 2023 net debt was $1.78 billion, including cash paid of $651 million and net debt assumed relating to the acquisition of Bonavista in the fourth quarter.

We paid $6 55 per share in combined beat and special dividends in 2023, and that's a 10% trailing yield.

We have elected to increase the base dividend as mentioned by 7% for.

For the first quarter of this year and we have now increased the base dividend a total of 13 times since we initiated the dividend in the first half of 2018.

Exit 2023, net debt was $1 78 billion.

Including the cash paid of $651 million and net debt assumed relating to the acquisition of Bonavist thing in the fourth quarter.

Michael L. Rose: We intend to reduce net debt throughout 2024, and we do remain committed to our long-term debt target of between $1.2 and $1.4 billion and that 0.3 times debt to cash flow rate. We have only booked, as we move into reserves, a couple more highlights. We've only booked 3,900 gross locations of a total drilling inventory of 23,724. So, as mentioned, 16.5% of that inventory is only booked in the year-end 23 2P reserve category. We replaced 368% of our 2023 annual production of 190 million BOEs with 2P additions of 698 million BOEs. 2023 PDP finding or FD&A costs were $8.94 per POE, excluding changes in future development capital, and that yielded a PDP reserve cycle ratio of 2.2.

We intend to reduce net debt through throughout 2024, and we do remain committed to our long term debt target of between one two and $1 4 billion, which is in that three times debt to cash flow range.

We have only booked.

We move into reserves couple more highlights we've only bought.

3900 gross locations of a total drilling inventory of 23000.

724, so as mentioned 16, 5% of that inventory only.

In the year end 'twenty three two P reserve category.

We replaced 368% of our 2023 annual production of $190 million with two additions of 698 million Boe.

2023, PDP, finding our MD&A costs were $8 94 per Boe.

Excluding changes in future development capital and that yielded a PDP reserves cycle ratio of two two.

Michael L. Rose: Our 2P reserve value before tax equates to a little over $117 per diluted share and after tax a little over $90 per diluted share, and that's based on the JAN 124 engineering price deck and a 10% discount rate. Specifically, on the 24 Capital Program, as mentioned, we've elected to reduce forecast capital expenditures by about $220 million. The budget reductions include a reduction in the rig count, a deferral of select exploration drilling, and certain facility projects.

R to P reserve value before tax equates to a little over 117 per diluted share.

After tax a little over $90 per diluted share and Thats based on the Jan 124 engineering price deck at a 10% discount rate.

Specifically on the 24 capital program.

As mentioned, we have elected to reduce our forecast capital expenditures by about $220 million.

The budget reductions include a reduction in the rig count a deferral of select exploration drilling and certain facility projects.

Michael L. Rose: And we reiterate, although our extensive Tier 1 drilling inventory of over 17 years is actually profitable at eco gas prices, around $1.50 per MCF, we do not believe that selling incremental gas volumes into the current very weak gas market is the best decision or return proposition for our shareholders. So forecast average 2024 natural gas production has been reduced by approximately 100 million per day from previous guidance, or 4%. So we've essentially eliminated any gas growth in 2024, and we definitely think that's the right thing to do. However, should prices improve on a sustained basis, we can pivot and materially grow production late in the year or early in 2025. Briefly on marketing, in 2023, our average realized natural gas price was $4.83 per mcf canadian, so that's 80% above the average 2023 ACO5A index price, which was $2.68 per mcf canadian, and our Marketing Diversification Portfolio and Strategic Hedging Program allow the company to consistently outperform local up-price.

We reiterate although our extensive tier one drilling inventory of over 17 years is actually profitable light vehicle gas prices around $1 50 per Mcf, we do not believe that selling incremental gas volumes into the current very weak gas market is the best positioned decision or written.

<unk> proposition for our shareholders.

So forecast average 2020 for natural gas production has been reduced by approximately 100 million per day from previous guidance.

Or 4%, so we've essentially eliminated any gas growth in 2024, and we definitely think thats the right thing to do.

Should prices improve on a sustained basis, we can pivot.

And materially grow production late in the year or early in 2025.

Briefly on marketing.

In 2023, our average realized Nat gas price was $4 83 per Mcf Canadian so that 80% above the average 2023 equal <unk> index price, which was $2 68 per Mcf and our marketing diversification portfolio and strategic hedging program.

Allow the company to consistently outperform local pricing.

Michael L. Rose: We expect to exit 2024 with approximately 1.21 BCF per day in exports to targeted markets, including a total of 754 million cubic feet per day delivered to a mix of JKM, the Western U.S., and the Pacific Northwest; those are the key premium markets. In January of this year, we completed our second LNG agreement, increasing exposure to the JKM index by entering into a net-backed agreement with Trafigura based on 62,500 MMBTU for a seven-year term starting Jan 2027, with the potential for extension to December 2039. That agreement is not dependent on FERC approval.

We expect to exit 2024 with approximately $1 two one bcf per day in exports to targeted markets.

<unk>, a total of 754 million cubic feet per day delivered to a mix of J P. A M.

The Western U S and the Pacific Northwest those are the key premium markets.

In January of this year, we completed our second LNG agreement.

Increasing exposure to the GKN index.

By entering into a netback agreement with Trafigura based on 62500 <unk>.

Btu for seven year term, starting Jan 2027.

With the potential for extension to December 2039, and that agreement is not dependent on incremental FERC approvals.

Michael L. Rose: Briefly on EP, we're excited about our Montigny well performance in BC as it continues to improve with the 23 outperforming wells from the previous three years. In BC, we've received 252 new drilling permits since January of 2023. The 24 program, or the Q1 program, has delivered several Alberta Deep Basin pads that are well above performance curve expectations, and they're at Smoky and Kakwa and along the ex-Buena Vista Glockenheit trend. A couple of the big highlights, of course, 10-26, that's a 3-well Wilrich C pad, tested at average per well rates of 29.3 million cubic feet per day of gas per well over a 70 The Kakwa 10-2 pad, again, a 3-well, this is a Wilrich pad, tested at average well rates of just a little under 20 million per day per well over a 112-hour test period. And the two most recent Glockenheit wells down dip on the trend have significantly outperformed. First tested at an average gas rate of 7.7 million cubic feet per day and 946 barrels per day of condensate, that was on a 134-hour flow test.

Briefly on <unk>.

We're excited about our Montney well performance NBC as it continues to improve with the 23 wells outperforming wells from the previous three years NBC, We've received 252 new drilling permits.

January of 2023.

24 program or the Q1 program.

Has delivered several Alberta deep basin pads that are well above the performance curve expectations and they're at Smokey and catalog and along the <unk> block in a trend.

A couple of the big highlights of course, 10% to 26% to three well we'll see.

<unk> tested an average per well rates of $29 3 million cubic feet per day of gas per well over 70 hour test during January the CAC will turn it to Pat again, a three well this is a well rich pad tested at average well rates of just a little under $20 million per day per well.

112 hour test period.

Two most recent block and eight wells on down dip on the trend.

Significantly outperform first tested at an average gas rate of seven 7 million cubic feet per day, and 946 barrels per day of condensate that was on a 134 hour flow test, we turned out well over to production in February and the second wells averaged 8 million a day of Nat gas.

Michael L. Rose: We turned that well over to production in February. The second well averaged 8 million barrels a day of natural gas, 850 barrels per day of condensate, and 1170 barrels per day of NGLs over the first 7 days of production. Importantly, we've also successfully drilled the first monobore well designed for the Glock trend, which we expect will ultimately reduce drilling costs by as much as 15-20%. In our Continuing Environmental Performance Improvement, or EPI, our Clean Tech Engineering team continues to develop and implement new proprietary emission reduction technologies, execute expanded water management initiatives, explore industry-leading methane mitigation technologies, and manage a large amount of third-party environmental research, which we pick and choose among. Since embarking on our Diesel Displacement Initiative, which is just one of them, for drilling rigs and frack spreads over six years ago, we've displaced a little over 135 million liters of diesel, which has provided an emission reduction of 87,000 plus tonnes of CO2, and importantly saved approximately $129 million, and that includes the cost of the make-up natural gas replacing the diesel. We continue to strive to have the lowest fresh water intensity in the industry.

850 barrels per day of condensate and.

11, 70 barrels per day of Ngls over the first seven days of production.

Accordingly, we have also successfully drilled the first mono bore.

Well designed for the block trend, which we expect will ultimately reduce drilling costs by as much as 15% to 20%.

On our continuing environmental performance improvement our epi.

Our clean Tech engineering team continues to develop and implement new proprietary emission reduction technologies execute expanded water management initiatives explore industry, leading methane mitigation technologies and manage a large amount of third party related environmental research, which.

We pick and choose amongst.

Since embarking on our diesel displacement initiative, which is just one of them.

For drilling rigs and Frac spreads over six years ago, we've displaced a little over 135 million liters of diesel which has provided an emission reduction that 87000 plus tons of Cotwo and importantly saved approximately $129 million and that includes the cost of the make.

Nat gas.

Replacing the diesel.

We continue to strive to have the lowest freshwater intensity in the industry in.

Operator: In 2022, we did at 0.11 barrels per BOE, 12 months after fracturing. And that extensive water storage and recycling infrastructure that we've diligently built over the last 7 or 8 years could prove highly beneficial in the event of an earthquake or drought-related water restrictions, which may or may not happen later in the year. So that was all I was going to say as far as formal remarks, and we're all here to answer questions you might have. Thank you. Ladies and gentlemen, we will now begin the question and answer session. If you have a question, please press the star followed by the 1 that is up there. You will hear a three-tone prompt acknowledging your request. Questions will be taken in the order received. Should you wish to cancel your request, please press the star followed by the 10. If you are using a speakerphone, please lift the handset before pressing any key.

In 'twenty two we did at one one.

<unk> per BOE 12 months after fracturing.

And that extensive water storage and recycling infrastructure that we diligently built over the last seven or eight years.

Could prove highly beneficial beneficial in the event of drought related water restrictions, which may or may not happen later in the year. So that was all I was going to say as far as formal remarks and now we're all here to answer questions you might have.

Thank you.

Ladies and gentlemen, we will now begin the question and answer session.

Did you have a question. Please press the star followed by the London is helpful.

You will USB Cohen Comped acknowledging your request.

Questions will be taken in the order received should you wish to cancel your request. Please press the star followed by the two if you are using a speaker phone. Please lift the handset before pressing any case once again that is star one should you wish to ask a question.

Operator: Once again, that is store number one. Should you wish to ask a question? Your first question is from Michael Harvey from RBC Capital Markets. Please ask your question. Yeah, sure. Good morning, guys.

Your first question is from Michael Harvey from RBC capital markets. Please ask your question.

Yeah sure good morning, guys.

Michael Steve Harvey: Thanks for taking the question. Just a couple things. So on the liquids, you mentioned it was BC Montaney driving that out of performance. Just wondering if you can comment on the specific sub-regions of the Montaney driving that, or if it was just kind of from all over.

Thanks for taking the question just a couple of things so on the liquids you mentioned it was <unk>.

BC Montney driving that performance just wondering if you can comment on.

The specific subregions of the Montney driving that or if it was just kind of from all over.

Michael L. Rose: And then just the mix of those liquids in 2024 looks pretty consistent with your last update in terms of the split between Condensate, et cetera, but just checking in on that. And then the last thing was just, there was a small technical revision downward of 46 million barrels. Any color on where that came from as I assume there's a bunch of moving parts in that figure that was provided?

And then just the mix of those liquids in 2024, it looks pretty consistent with your last update in terms of the split between condensate et cetera, but just checking in on that.

Then last thing was just there was a small tech revision downward 46 million barrels.

Just any color on where that came from as I assume there is a bunch of moving parts in that figure that was provided.

Michael L. Rose: Thanks. Sure, on the liquids, yeah, most of the corporate outperformance is driven by the Monty, and most of that is in the North Monty, and it in part relates to a little more plug-and-perf completion style on the tighter, more liquid-rich horizons. On the tech revision on the 2P of a little under 50 million BOEs, the lion's share of which related to a couple of zones of the six at Gundy underperforming what we had expected, and so it's a little under 1% of the total reserve base. And the mix, sorry Michael, you had a third question in there; the mix is largely the same between the liquids.

Sure.

The liquids.

Most of the corporate outperformance is driven by the Montney and most of that is in the north Montney.

In part relates to.

Little more plug and perf completion style on the tighter and more liquid rich.

Horizons.

On the.

Tech revision on the <unk> of a little under $50 million.

The lion's share of that related to a couple of zones of the six that got any underperforming.

What we had expected.

And so it's a little under 1% of the total.

Our reserve base.

And the mix sorry, Michael you had a third question in there the mix.

It's largely the same.

Between the liquids.

Michael Steve Harvey: I mean, we're getting a lot more condensate in the deep basin right now, but we'll see how that performs through the balance of the year. Great. Appreciate the call, Mike.

Getting a lot more condensate in the deep basin right now, but we'll see how that.

Performance through the balance of the year.

Great I appreciate the color Mike.

Operator: Thanks. Thank you. Once again, please press star 1 should you wish to ask a question.

Thanks.

Thank you once again, please press star one should you wish to ask a question.

Okay.

Operator: Thank you. Your next question is from Dawn Texter from BFT Energy. Please ask your question. Good morning, Mike.

Next question is from John texture from DFT Energy. Please ask your question.

Good morning, Mike Mike I know you are directly involved in Canada, LNG, but could you just.

Donald Fleming Textor: Mike, I know you're not directly involved in Canada LNG, but could you just, you know, a lot more about it than I do? Could you give us a status report on that? When do you think they will start putting gas in the line? And when do you think they will really start exporting gas? Yeah, well, actually, we probably don't know a lot more than you do about it because we just rely mostly on the same public data. We're hearing encouraging things that there's going to be some gaps going through the CGL line, which is completed. And that's going to happen at some point in the second half of 2024.

You know how a lot more about it in Idaho could you give us a status report there when do you think you can start putting gas in the line and when do you think that really started exporting gas.

Well actually we probably don't know a lot more than you do.

Your line is because we just relied mostly on the same public data, we're hearing encouraging things that theres going to be some gas going through the <unk> line, which is completed.

And that's going to happen at some point in the second half of 2024, but we don't know the exact start up and when we don't know the exact volume Jamie anything else you want to add I think in general we expect commissioning to kind of ramp up in the back end of the year in the plant to be hopefully fully commissioned in 2025, which will be 2 billion cubic feet a day.

Michael L. Rose: But we don't know the exact startup cost, and we don't know the exact volume. Jamie, anything else you want to add? Yeah, I think in general, we expect commissioning to kind of ramp up at the back end of the year and the plants to be hopefully fully commissioned in 2025, which will be two billion cubic feet a day pulled out of the WCSB. That's a 13 to 14 percent demand increase, and it's going to be significant for our market. And would you care to give your guidance as to what's going to happen with the differentials between AECO-C gas and Dimex gas? We expect some tightening. We think that you can see basis tighten a little bit here, 25 to 50 cents on average, but we also think that there could be volatility around that number.

Pulled out of the WCS at 13% to 14% demand increase and it's going to be significant for our market.

Hum.

Would you care to give you guidance as to what's going to happen on differentials between <unk>.

<unk> and <unk>.

<unk> gas.

We expect some tightening we think that you could see basis tightened a little bit here, 25% to 50 on average, but we also think that there could be volatility around that number maybe some periods are very firm pricing, maybe some periods at the plants aren't running at full capacity, where the pricing is a little bit losers. So we're prepared for both improving market dynamics, but also protect.

Jamie Heard: Maybe some periods of very firm pricing, maybe some periods if the plant's not running at full capacity where the price is a little bit looser. So we're prepared for both improving market dynamics and potentially more volatile market dynamics ahead of time. Thank you very much. Thank you. Thank you. Your next question is from Cam Bean from Skill Japan. Please ask your question. Good morning, guys.

More volatile market dynamics ahead of us.

Okay. Thank you very much.

Thank you.

Thank you. Your next question is from Jim Beam comes Scotia Bank. Please ask your question.

Good morning, guys. Thanks for taking my question.

Cameron Bean: Thanks for taking my question. I was just curious if you could provide any color on where regionally that $150 million of development capital was going to come from. I'd say probably more than two-thirds of it out of the Deep Basin, and then the balance out of BC, some of it being facility-related capital.

Just curious if you could provide any color on where regionally where that $150 million of development capital was going to come out from.

I'd say, it's probably more than two thirds of it out of the deep basin.

And then the balance out of BC some of it being facility related capital.

Michael L. Rose: Awesome. Thank you very much. Thank you. Your next question is from Mike Dunn from Cecil. Please ask your question.

Awesome. Thank you very much.

No.

Thank you. Your next question is from Mike Dunn from Stifel. Please ask your question.

Well thanks.

Michael Paul Dunn: Well, thanks. Yeah, Mike, just wondering, you know, as we've looked at what some of the US peers have done with their production cuts for gas or their cuts to their outlook. I'm just curious here if we do see some really weak prices again. You know, given your low operating costs, you wouldn't be the first to shut down production. But what sort of spot, eco price, I guess, or station two do you guys start to think about curtailing production and maybe the scope of what you know might be?

Yes, Mike just wondering.

We've looked at what some of the U S peers have done with <unk>.

Their production cuts for gas or the cuts to their outlook.

I'm just curious here, if we do see some really weak prices again.

Given your low operating costs, you wouldn't be the first to shut in production, but what sort of spot coal price I guess or station two do you guys start to.

Think about curtailing production.

Maybe the scope of what that.

Michael L. Rose: Is there a lot that would maybe go offline at $1.50, $1.40, or not really? Well, we make money at that price. I mean, we've had an activity cut rather than just a shut-down because we think that's actually better for the markets and it's better for our free cash flow to do it that way. So we've eliminated our growth. In the past, we have shut gas in on a very short-term basis, and that related to TransCanada Maintenance when they were doing the NGT build-up that you recall. And there would be days when you had a zero price, or two or three days, and we would shut in there. It's usually sundown, which is right on the BC-Alberta border, and it's the driest asset we have from a liquid content standpoint.

It might be is there a lot that would maybe go offline at a buck 50 of block 40 or are not really well.

Well, we make money at that price I mean, we've had an activity rather than just the shut in because we think that's actually better.

For the markets and it's better for our free cash flow to do it that way so we've eliminated our growth.

In the past we have shut gas in on a very short term basis.

And that related to Trans Canada maintenance when they were doing the <unk> build out that you will recall and there would be days when you had zero price or two or three days and we would shut in there thats, usually sundown, which is right on the BC, Alberta border edits that Darius.

That we have from our liquid content standpoint.

Michael Paul Dunn: So we watch it, but we have no plans to shut it in. But, as you say, we'll just have to see where the price goes. Yeah, fair enough. Makes sense. Thanks, Mike. That's it for me.

So.

We watch it but we have no plans to shut in but as you say, we will just have to see where the price goes.

Yes fair enough makes sense, thanks, Mike Thats It for me.

Operator: Your next question is from Chris Warko from the Calgary Herald. Please ask your question. Hi Mike, thanks for taking my question. I'm wondering whether your outlook for Canadian gas markets has substantially changed at all for 2025, given what we're seeing right now in the marketplace but also, obviously, the startup of LNG exports coming out of this country next year? Yeah, no, it hasn't.

Thanks.

Oh.

Thank you. Your next question is from Chris Black Hog farm to Calgary Herald. Please ask your question.

Hi, Mike Thanks for taking my question I'm wondering whether your outlook for Canadian gas markets has substantially changed at all for 2025, given what we're seeing right now in the marketplace, but also obviously the startup of LNG exports coming out of this country next year.

No it hasn't we're quite bullish on what happens.

Chris Warko: We're quite bullish on what happens to our two local hubs, ECO and Station 2, when you pull two BCF a day west out of a basin that's, you know, largely in the supply-demand balance. So no, we remain super constructive, to be honest, but right now, in 2024, the price is not good. So we'll save those incremental growth methane molecules for that much better price we expect in 2025. And just to follow up, are there any plans, I guess, or do you see yourself shifting towards producing more condensate later in the year as you're sort of moving some of that capital around? Well, our liquid production guidance is actually up over the year, but I think that will happen in all the remaining three quarters; it's not specifically timed to any particular date in the second half. That's all for me.

Through our two local hubs vehicle and station do win.

<unk> two Bcf a day west out of the basin.

Largely in supply demand balance so no we remain super construct.

To be honest, but right now in 2020 for the prices not as good.

So we'll save those incremental growth methane molecules for that much better price, we expect in 2025.

Yeah.

And just to follow up is there any plans I guess, where do you see yourself shifting towards producing more condensate later in the year has your sort of moving some of that capital around.

While our liquids production guidance is actually up over the year.

But I think that will happen in all of the remaining three quarters not specifically tied to.

Any particular date in the second half.

Michael L. Rose: Thank you. Thank you. Your next question is from Ben Brown from Olin. Please ask your question. Oh, it might have been Fai Lee. Hello? Yeah, hi Fai. Yeah, I saw the odd one brown, so I figured it was you.

That's all for me thank you.

Thanks.

Thank you.

Our next question is from Dan Brennan from Goldman Please ask your question.

So it might have been a fight that.

Hello.

Yeah, Hi.

Yes, I saw the OSM round, so I figured it with you.

Ben Brown: It confused me a bit, sorry about that. Then, I just want to touch on the free cash flow allocation, you know, the forecast at the current strip is $1.2 billion, and after you net out the base dividend and I guess the March special, you'll have, looks like you'll have around $600 million to allocate between future special dividends, which you've committed to, as well as reducing debt. I'm just wondering what we should think about this split between debt reduction and the stock dividend. I can start, and we can probably round it up as a team.

Sorry about that.

Yes.

I just have a question on the free cash flow allocation.

Forecast <unk>, one 2 billion.

And after you net out the base dividend and I guess, the March, especially you'll have it looks like you'll have around 600 million to allocate between future special dividends with <unk>.

Im committed to as well as reducing debt I'm just wondering how should we think about the split between debt reduction in the EBITDA.

If I can start and we can follow you brought it up as a team so.

Jamie Heard: So, maybe it's easier to think about it on a per share basis. So, free cash flow per share this year is $3.35 on the February 15th strip. And then the dividend, as you mentioned, the base would be $1.20. And the first special is $0.50.

Maybe it's easier to think about it on a per share basis free cash flow per share. This year is $3 35 on the February 15th strip and then the dividend as you mentioned the base would be $1 20. The first special is 50.

Jamie Heard: We could continue paying that $0.50 dividend four times in a row and still have headroom. And I would note that since February 15th, commodity prices have actually improved somewhat. So, we should see some upside to this number already, and we'll kind of see how the year progresses. On leverage, our aim long-term is to get back to that $1.2 to $1.4 billion target, but we don't necessarily need to achieve that in any one specific time period.

We could continue paying that 50 dividend four times in a row and still have headroom and I would note that since February 15th commodity prices had actually improved somewhat so we would see some upside to this number already and what kind of see how the year progresses on leverage our aim long term is to get back to that one two to $1 $4 billion target, but we don't necessarily need.

To achieve that at any one specific time period, it's just a progression we're going to be moving towards.

Jamie Heard: It's just a progression we're going to be moving towards. So, I would anticipate some deleveraging this year, but not necessarily as much deleveraging as needed to get into the range in one year. And so, you know, for the balance of the year, we'll be monitoring strip pricing, which, as I mentioned, has already been improving, and allocating some cash flow back to the balance sheet. But, in general, continuing to return the vast majority of free cash flow back to shareholders. Okay, that's great. We appreciate the color there.

So I would anticipate some deleveraging this year, but not necessarily as much deleveraging is needed to get into the range in one Adam and so for balance of year, we'll be monitoring strip pricing, which as I mentioned has already been improving and allocating some cash flow back to the balance sheet, but in general continuing to return the vast majority of free cash flow.

Back to shareholders.

Okay. That's great I appreciate the color there.

Fai Lee: And in terms of the commitment to the special dividends, were there any thoughts given to doing the share buybacks, given where the current share price is? Or I'm just wondering if that, you know, how that factored into the decision to pay special dividends through the remainder of the year? Yeah, sure. We always evergreen our NCIB, and we're, you know, maintaining our defensive posture for potentially using it if there's an extreme price dislocation. So it is always, you know, one of the potential uses of that matrix of free cash flow.

In terms of the commitment todays special dividends were there any thought given to doing share buybacks, given where the current share prices or.

I'm just wondering.

Scott.

That factored into decision for the pain.

Paying special dividends through the remainder of the year.

Yes, sure I mean, we always evergreen or NCI.

Maintaining our defensive posture.

For potentially using it if there is an extreme price dislocation.

So it is always.

One of the potential uses of.

That matrix of free cash flow.

Okay, alright so.

Jamie Heard: Okay. All right. So, in that event, would we assume that maybe there'll be a change in plans for a special dividend or would you possibly maybe increase your leverage a bit and temporarily? Well, we're not going to use the balance sheet to pay special dividends.

And that is that would we assume that maybe they'll be trained to pilot a special dividend or would you possibly.

Maybe increase your leverage a bit.

Temporarily.

We're not going to use the balance sheet.

Special dividends.

Fai Lee: Okay, all right, thank you. Yeah, thanks. Thank you. There are no further questions at this time. Please proceed. Thank you very much. We'll see you next quarter. Thank you. Ladies and gentlemen, the conference has now ended. Thank you all for joining us. You may all disconnect.

Okay alright, thank you.

Yes. Thanks.

Thank you there are no further questions at this time. Please proceed.

Thank you very much.

We'll see you next quarter.

Okay.

Thank you.

Ladies and gentlemen, the conference has now ended thank you all for joining you may all disconnect.