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Operator: Good morning, ladies and gentlemen, and welcome to the Tourmaline Q3 2025 Results Conference Call. [Operator Instructions] This call is being recorded on Thursday, November 6, 2025. I would now like to turn the conference over to Scott Kirker. Please go ahead.
W. Kirker: Thank you, operator, and welcome, everyone, to our discussion of Tourmaline's financial and operating results as at September 30, 2025, and for the 3 and 9 months ended September 30, 2025 and 2024. 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 SEDAR 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 with Mike speaking to some of the highlights of the last quarter and our year so far. After his remarks, we'll be open for questions. Go ahead, Mike.
Michael Rose: Thanks, Scott, and thanks, everybody, for dialing in. We're pleased to go through Q3 and then answer questions that you may have. A few highlights. Q3 '25 average production of 634,750 BOEs per day was at the high end of our anticipated guidance range of 625,000 to 635,000 BOEs per day despite storage injections and shut-ins during the quarter. We're pleased to announce that we have entered into a long-term natural gas storage agreement with AltaGas at their Dimsdale storage facility, and we view the addition of another large storage position as a strategic opportunity to enhance financial performance and strengthen operational flexibility in volatile natural gas price environments like we just went through this past summer. We've also entered into 2 short-term and long-term LNG gas supply contracts which complement our existing extensive portfolio. Looking specifically at production, fourth quarter production is expected to average between 655,000 and 665,000 BOEs per day with a '25 exit volume of 680,000 to 700,000 BOEs per day. Our third quarter liquids production of a little over 147,000 barrels per day was up 4% quarter-over-quarter. And our '26 average production guidance of 690,000 to 710,000 BOEs per day remains unchanged as does the current multiyear EP plan, which is forecast to yield 30% high-margin production growth to 850,000 BOEs per day by 2031. Third quarter 2025 cash flow was $720 million and third quarter '25 earnings were $190 million. Our third quarter realizations were impacted by unusually large natural gas export maintenance outages, both the East Gate and the West Gate. As a result of these outages, AECO and Station 2 pricing averaged $0.64 and $0.48 per Mcf, respectively, during the quarter. And while we curtailed gas supply during the weakest local price days, the sustained low local prices were the primary reason for lower than our expected third quarter cash flow. The curtailments on export pipelines reduced our volumes accessing downstream markets as well, and that includes our premium markets, such as the Gulf Coast and the Western U.S. by approximately 155 million cubic feet per day. So instead, these volumes were sold into AECO and Station 2 spot prices, and that meaningfully impacted our September natural gas revenue. On a positive note, the force majeure on the Great Lakes pipeline ended in early October and East Gate exports are at normal levels and the West Gate maintenance ends during this month of November. Looking ahead, with the benefit of LNG Canada demand creating additional capacity on local egress pipelines, second and third quarter 2026 AECO pricing is currently averaging $3 an Mcf compared to $1.18 for the same period in 2025. And we think additional upside should be created if AECO basis tightens further, and that is what we anticipate happening. Third quarter 2025 EP expenditures were $825 million. The full year EP capital budget remains unchanged at $2.6 billion to $2.85 billion. We closed a $71.7 million transaction with Topaz Energy Corp., whereby Topaz purchased a GOR on the recently acquired Saguaro and Strathcona Groundbirch Northeast BC Montney development lands. And in addition, on October 28, we completed a secondary offering of Topaz common shares for gross proceeds of approximately $230 million. Moving to marketing. Lots of activity as we continue to vertically integrate our gas business and maximize future realized prices. We have an average of 1.2 Bcf per day of nat gas hedged for the remainder of 2025 at a weighted average fixed price of CAD 4.33 per Mcf. This includes 57 million cubic feet per day hedged at a weighted average price of CAD 20.13 per Mcf in international markets and 109 million cubic feet per day at a weighted average price of $6.86 per Mcf in the Western U.S. markets. Q3 '25 AECO and Station 2 nat gas prices were the weakest in over 30 years. And as mentioned, that negatively impacted cash flow. However, prices are improving thus far in the fourth quarter and the 2026 strip price outlook continues to migrate upwards. We are pleased to enter into that Dimsdale storage deal. We'll have access to 6 Bcf of storage capacity starting in April for a 10-year term with the ability to increase to 10 Bcf in the event that AltaGas takes FID on Phase 2. And we view the addition of another large storage position as a really strategic opportunity to enhance financial performance and provide operational flexibility with these very volatile prices. On the LNG front, we've entered into several new supply contracts as detailed in the release, and I won't go through them, but they're there for you to read. In aggregate, we'll have an average of 213,000 MMBtus exposed to international pricing in '26. That will grow to 250,000 by exit '27 and 330,000 by exit '28. So a very attractive progression. Turning to the capital budget and the EP plan. As mentioned, spending in the quarter was $825.5 million as we executed capital projects deferred from Q2, along with the original Q3 budgeted items really to prepare for incremental production volumes in advance of higher anticipated winter gas prices, which are materializing. Our full year EP spending remains unchanged for 2025 and 2026. The '26 EP capital program is $2.9 billion, and that is unchanged from the release on July 29, 2025. Utilizing current strip pricing, our EP plan anticipates '26 cash flow of approximately $4 billion and free cash flow of approximately $0.9 billion. The strip pricing includes a '26 AECO basis of $1.66 per Mcf, and we anticipate that basis tightening towards USD 1 as the basin dynamics adjust for LNG Canada's demand. And for every USD 0.10 per Mcf that AECO basis tightens, our '26 cash flow and free cash flow would increase by approximately $50 million. And should natural gas prices weaken in 2026, we certainly have the option to reduce capital spending as appropriate to optimize free cash flow and our planned shareholder returns. Approximately $200 million to $250 million of currently planned capital spending could be deferred in such a low price scenario, and that would really have only a minor impact on '26 production guidance. On our cost reduction focus and margin improvement initiatives, the ongoing Northeast BC development project and infrastructure build-out will provide both significant growth and margin expansion by improving all of our operating metrics. Q3 2025 corporate OpEx of $4.80 per BOE was down $0.34 a BOE from the first half of this year, so approximately a 7% improvement. And early components of the Northeast BC build-out have been completed, and that has initiated the cost reduction progression and is contributing to the reduction in OpEx in the third quarter, and this process will really accelerate going forward. The Northeast BC development project is anticipated to systematically reduce combined corporate OpEx and transportation costs by at least $1 per BOE as it is put in place over the next 6 years. And we see the opportunity for meaningful progress on this target in 2026 and all subsequent years. And there is potential to increase the overall total long-term target moving forward. We have a comprehensive corporate focus on reducing all aspects of the cost equation as well as our per well EP capital costs in 2026. So we're targeting a 5% OpEx reduction in the Deep Basin next year and targeting a further 5% reduction in D&C costs over currently budgeted levels. And these reductions are not captured in the multiyear EP plan yet because we'll make sure we realize them first. And we've always had a very strong cost structure, and we plan to make it even stronger going forward. We have elected to pursue the potential sale of our Peace River High light oil and gas complex, so the Charlie Lake Play, which we actually pioneered back in Duvernay Oil Corp days. If completed, this sale would further lower corporate OpEx and provide proceeds that could be reinvested into our higher-margin BC growth assets or emerging EP opportunities that we've assembled in the Deep Basin. So this initiative is just a subset of the significant internal value creation opportunities that exist within the company's overall portfolio. Specifically on E&P in the quarter, we drilled 68 wells, completed 88 wells and entered the fourth quarter with 38 DUCs, the majority of which are expected to be completed in the near term should gas prices continue to improve. We were very pleased our 25 Northeast BC Montney IP90 well performance to date is up 26% over the 5-year average performance as we drill steadily longer horizontal wells in that complex and the percentage of plug and perf style stimulations has been increased. And despite these more expensive completions, our 2025 Montney D&C costs are trending down on a per lateral foot basis. Our new pool new zone exploration success continues across all complexes, and we have 12 to 15 new pool or follow-up delineation wells currently in the Q4 '25 and 2026 drilling program. So lots of exciting opportunities on that front. On the dividend, our Board has declared a special dividend of $0.25 per share. That will be payable on November 25 to shareholders of record on November 14, 2025. And the company intends to declare the quarterly base dividend of $0.50 per share in December. We commenced paying special dividends in September of 2021, and that special dividend has varied between $0.35 per share and $2.25 per share until this quarter where it's $0.25. And while the '26 free cash flow outlook continues to improve, we will continue to find the balance between the planned EP growth program and the size and cadence of the special dividend. And I think that's enough for formal remarks, and there's 4 of us here ready to answer questions you may have.
Operator: [Operator Instructions] Your first question is from Kale Akamine from Bank of America.
Kaleinoheaokealaula Akamine: I want to start by asking on the Peace River sale. I'm wondering if you can give us any clues as to how you're thinking about the value of that asset. And I guess, fundamentally, if you don't see the price that you want, would you consider retaining the asset? And the part B of the question is, this is essentially a fully developed position that comes with midstream, gas processing, et cetera. Is there any chance that you would hold on to certain assets?
Michael Rose: I'll kind of -- thanks, Kale. Not going to give you what our price expectations are at this point because the process is going on. I think you would appreciate that. If it doesn't hit a certain value, we're not going to sell it. You're right, it is a fully developed asset, and I think it's very attractive to people that are looking for new opportunities like that. It would be a great way to start a company. And I think we'd sell it all together rather than break it up. And I did mention in the formal remarks, I mean, it's -- this is a play that we actually invented, started it vertically in Duvernay Oil Corp. days, created a company called X Shaw, ended up buying it back when Tourmaline was in existence. And then the play at a reverse where we had a different application of horizontal multiphase fracking drilling for the Charlie Lake, and it's worked extremely well. So why are we selling it? Well, the reality is that the returns from investing in our 2 very large gas complexes kind of always outstrip the returns from growing the Peace River High asset in a material way. And so it's been essentially on maintenance capital for 4 to 5 years. And we think we have a whole gamut of opportunities in both gas complexes, and we can use the proceeds to kind of more profitably grow with lower OpEx in those 2 gas complexes. So that's kind of the rationale behind it.
Kaleinoheaokealaula Akamine: That's great, Mike. I appreciate that. And for the second question, in the release, you called out a handful of what I'll call cash management items. And given the recent price environment for AECO Gas, I think that's prudent, although things seem to be on the mend today if we're looking at AECO prices. We just talked about the Peace River sale, but there's also Topaz equity and there's CapEx deferrals that you have in your back pocket. I'll leave the Topaz question for someone else, but I'm wondering how you would characterize the CapEx deferral of $200 million to $250 million. Is that drilling related? Or is that infrastructure related?
Michael Rose: It would be primarily drilling related if we exercise on that in a weaker price environment than we're in today, we would carry on with the BC infra buildout. And I think you can see the rationale for that, that if prices are significantly weaker, we hold the volumes back. And so that would mean the D&C budget would be reduced.
Operator: Your next question is from Patrick O'Rourke from ATB Capital Management -- sorry, ATB Capital Markets.
Patrick O'Rourke: Maybe just a follow-on with respect to the $200 million to $250 million in potential reductions here. Just wondering what's sort of the time frame for those decision points rolling out into 2026? And then is there any sort of quantification on '27, '28, et cetera, from a volume perspective? Or would this -- my thought is being a company with such a large defined inventory, really well-defined growth on the back of that inventory, would at any point, you consider sort of gearing back on exploration in the near term to preserve capital?
Michael Rose: We could do that, although the exploration program has generated opportunities that should we proceed with the sale of the Peace River High complex that over 2 or 3 years, we think would fully replace the volumes from that complex. And as far as timing on when we make those decisions, I think we see if the Peace River High sells first because obviously, there's a maintenance capital budget item associated with that complex in the current '26 budget. So we'd be adjusting the '26 budget at that point. And by year-end, I think we'll have a pretty good look at where the '26 strip is going to be, where basis gets to. And I think it was referenced already that AECO is starting to repair itself. The West Gate is back open today, but there is another restriction in a week or so, and then it's free and clear. So we should be switching to or flipping to withdrawals from storage now. And then that will drive price and receipts were a little higher in the basin over the past week and a good portion of that was due to gas backed up because of storms on the West Coast and LNG Canada was not picking the same volumes west that they have been, which I think has gotten up as high as [ 800,000 ]...
Patrick O'Rourke: And then just thinking about sort of the interplay between the balance sheet and potential for special dividends. I know -- I don't want to call it caution, but obviously, it's been a sweep of free cash flow. Debt was a little higher. You've got the proceeds coming in from the Topaz share sale. So that will help. But how do you think about above and beyond the base dividend free cash flow allocation between that special dividend and maybe a little bit more debt reduction in the current environment?
Michael Rose: Yes. I mean we're thinking about all those things. And I think we said it reasonably clearly in the press release, we do not intend to use the balance sheet to fund special dividends. I think having 2 quarters of the lowest AECO prices in 30 years is a rare circumstance. And for Q3, paying the special using the balance sheet was one of those rare circumstances. But we will continue to look at the growth capital and the special dividend potential and find that balance.
Operator: Your next question is from Sam Burwell from Jefferies.
George Burwell: Just another question on the CapEx flexibility. Just curious like what drives that decision? What's -- how do you frame it? Is it based on not wanting to outspend after paying the base dividend? And then like what sort of time frame in terms of like viewing the strip or your view on gas prices are we looking at? Is this like months, some sort of medium-term time horizon? Just curious about how you're thinking about potentially flexing down the CapEx?
Michael Rose: Yes. I mean the main control, of course, is the gas price and then everything flows from that. This winter, we're already seeing cash gas prices recover. We're seeing very strong November, December, January, we think there's potential for that to get stronger still. I think all operators are reacting to that. We wouldn't expect any curtailed volume today. So you're kind of seeing fully loaded receipts, and it's not scary. Year-over-year growth is very modest, and we think that will allow this winter strip to improve. Tourmaline has a natural recalibration every spring and breakup. So as we come out of this winter and look ahead to what summer and winter following strip looks like in the months of March, April, May, that's a very natural time to calibrate the intensity of drilling for the back half of the year. And I think that would be a good time for us to also calibrate on free cash and make sure we're still delivering what we've always planned, which is that 5% growth and in excess of $1 billion a year of free cash flow.
George Burwell: Understood. And then sort of tying into that a little bit on the Canadian gas macro, like supply has come up a bit, granted that shut-ins coming back and it's sort of typical seasonality and the prices come up. But do you think that there's more room for supply to come on? And just asking this because we are going to get more demand from Train 1 pulling more consistently and then Train 2 pulling another Bcf a day next year. So just curious about your view on supply-demand balance and how much supply can realistically come on to fill the incremental demand from LNG Canada Train 2?
Michael Rose: Yes. We regularly refresh this work. And as I was saying, November looks relatively flat to last year, and we don't believe we're curtailed much at all as a basin today. Our expectation is next year grows well shy of 1 billion cubic feet a day on an annual per annum basis. Our number would be around 0.6, 0.7 exit over exit growth. We think actually might even be shy of that, around 0.5 Bcf a day. And to your point, LNG Canada will go from not doing anything in the first half of this year to doing close to and up to 2 billion cubic feet a day, we think as early as the first quarter of 2026. So that's a very meaningful demand change. And the basin will need to react to that with less exports to the United States, and the mechanism to achieve those less exports will be a tighter basis. And we think that will transpire over the next several months. We think there's other tailwinds at play. We believe the Biden expansion on the Northern border is a benefit to the Canadian export picture. It tightens up our basin Erestill. And we also think there's going to likely be power consumption and power announcements over the next 12 months that helps spur long-term demand thinking and tighten up '27, '28, '29 basis picture as well. So from our perspective, everything we are looking to see for this winter and the year ahead is transpiring. We are not seeing a wall of gas answer stronger cash prices. We are seeing LNG Canada ramp very well, and we continue to see lots of green shoots in local demand, whether it be power or [indiscernible]. And I think it will take Canada and Alberta specifically getting a little cooler here in the next 3 weeks to see what the draws ultimately look like on a year-over-year basis. And I think when we look at draws per week in December and compare them to what we were drawing last year, it could be almost a double. And I think that starts to wake the market up. Yes. And the last time the basin had a demand increment like LNG Canada adds to 2 Bs a day was start-up of Alliance. And I think that's flipped the differential for 3 years.
Operator: Your next question is from Aaron Bilkoski from TD Cowen.
Aaron Bilkoski: I have another question on the Peace River High. If you do ultimately sell it, should we expect you to use the proceeds to add capital to the multiyear plan? Or is the plan to simply redirect some of that maintenance capital that was being spent on the Charlie Lake into the Montney and the Deep Basin?
Michael Rose: Yes. More of the latter, Aaron, at this point. I think in order for us to add capital in the EP plan, we want to see strong commodity prices provide that signal. So at this point, it's going to delever the balance sheet. And it's another source of funding for this infrastructure growth that's going to start to add that incremental cash flow and free cash flow that, frankly, we're going to see -- we saw some of it this quarter. We're going to see more of it in '26. And then as Aken comes on and Groundbirch comes on over the years ahead, you're going to see that structural cash flow and free cash flow start. So it's funding that build.
Operator: Your next question is from Jamie Kubik from CIBC.
James Kubik: Aaron sort of asked the question I was going to ask her, but I'll ask a little bit of a different one. Can you just talk about how you're thinking about debt levels in the business? Is there a target in mind that you're driving to? Is it a function of forward cash flow? Just a bit more color on your thought process around this would be great.
Michael Rose: Well, I think we hit our kind of peak debt metric right now at 0.5x to 0.6x at the bottom of the cycle. So that will drive down to 0.2 to 0.3 as we move towards, we think, a more sustainable long-term price cycle. So we're going to keep that pristine balance sheet focus that we've always had, Jamie.
James Kubik: Okay. And can I ask maybe is the peak debt level where you're at sort of right now, is that a bit of a driver on the Peace River High disposition? Or is it more a function of just capital allocation between your various assets?
Michael Rose: It's for sure, the latter, it's capital allocation. I mean we've been thinking about selling the Peace River High complex for 2 or 3 years, to be honest, simply because it wasn't getting rewarded with growth capital because we had more attractive projects in the 2 gas complexes. And so it feels like this is probably the right time, and there's considerable interest in it. And worth flagging, Jamie, the interest is also what helps spur the process. There is interested parties that are looking to enter this basin, and they have unsolicitedly given us indications of value or interest in acquiring the asset. And so now running the process allows all of them to come to the table with their best number at the same time.
Operator: Your next question is from Josef Schachter from Schachter Energy Research.
Josef Schachter: Two of them. First thing, you guys have a great track record of making acquisitions in the past. When you look at your 2 core areas versus the M&A market, we just saw the NuVista deal, do you see M&A as part of the growth opportunity? Or is your internal opportunities just that much better?
Michael Rose: Yes. We went through like 5 years of putting primarily the BC Montney gas complex together through or expanding it through a whole series of acquisitions from COVID on. And we have put in place now the BC build-out infrastructure for the next 5 or 6 years. Now we're going to go realize all the upside and all the value from those really well-timed acquisitions. So we'll always look at perhaps small asset tuck-ins. But right now, it's -- the focus is much more on organic growth from the extensive inventories we have really in both gas complexes.
Josef Schachter: Super. Second question, the Topaz question, did a big sell-down here. Do you see using more sales and then get below 10%, which then allows you to move without market fluctuations?
Michael Rose: We have no plans in the short or medium term to dispose of any more of the Topaz shares. But we're super excited how that the whole Topaz story has unfolded and grown. And I think it's just been great all the way along. So we're happy to be shareholders.
Operator: Your next question is from Fai Lee from Odlum Brown.
Fai Lee: You just touched on it a little earlier about, I guess, growing power demand. There's obviously some bullish projections for gas demand to meet growing electric demand from data centers, artificial intelligence. And I'm just wondering how this on a longer-term basis could maybe possibly affect your strategy for marketing gas? And if you've had any consideration of specific steps you could take to capitalize on these opportunities. For example, do you think you'll ever have like direct gas supply agreements with data center builders? Or I'm just wondering how you're thinking about that.
Michael Rose: Yes. We're evaluating that opportunity, Fai. And we would look at it as just another sleeve of our overall gas diversification. But we do have lots to offer. I mean we have many plant sites. We have water. We have power redundancy. We're close to fiber. We're close to the grid. We can provide the CCUS solution, although we have very low CI gas to begin with. And so yes, we're assessing whether that's an opportunity to further diversify our very diversified marketing portfolio already.
Fai Lee: Okay. So you're looking at that. And I'm just wondering on the other side, have you been approached from data center builders or people saying, looking at the advantages that you can offer and say, maybe working with them. Is that kind of -- have we gotten to that level? Or it's just kind of just too preliminary at this point?
Michael Rose: Yes, there's been lots of conversations, I would say, early in stage, where people are trying to understand how this is all going to work. One of the first things that people were trying to understand first was what the ASO allocation would be and who would be a recipient of that ASO allocation. So that's happened. And we would be the first to cheer on projects like greenlight because that will help consume gas in basin. And the reality is we can build a lot of these. 1 gigawatt on a high-efficient power plant will only consume roughly 150 million cubic feet a day. So we think you could do 10 in short order, and you would still find the basin in balance, and we'd be able to answer that call. And so as operators understood how much ASO allocation they might get, now we're starting to move to that kind of Phase 2 where it's a bring your own power effort and operators are looking to add generation to their projects, and then they need gas supply for that generation. So we would fit naturally into all those conversations. We're having them. As Mike was saying, one of the areas I think we were probably most interested in is those colocation opportunities because it allows us to offer more than one service. And when you offer multiple services to a counterparty, you can enjoy that business. And so we have great sites across our asset base that many of them actually are very, very suitable for this kind of activity. And I think over the next 12 months, we should see all sorts of different data center announcements, some of which should be in the Heartland and we connect to ASO and some of which will be closer to the resource and have a behind fence strategy. And I think we're working hard on making sure we're positioned well to participate in those that are attractive to us.
Operator: Your next question is from Neil Mehta from Goldman Sachs.
Neil Mehta: Talking through 2026 as well. And as we think about '26, maybe you could talk about cyclical versus structural cost deflation. We continue to be in a relatively favorable oil services environment for the E&Ps. And so just you're curious if you're able to capture some of that cyclical deflation as opposed to maybe some of the structural benefits as well. So just the cost environment going into '26.
Michael Rose: Yes. It is -- you're right, Neil. It is a little bit more favorable on the service cost side and D&C costs through this winter. And I think we kind of eyeballed 5% reduction in the press release from where we were mid-2025. We're most excited about the operating cost reductions that we've started to achieve already, and they're structural and repeatable, and they will accelerate over the next couple of years, and they marry up well to base dividend increases.
Neil Mehta: And you talked a little bit about the LNG ramp in Western Canada, but maybe you could spend a little bit more time talking about the Shell ramp specifically and how you guys are thinking about that as the driver that could potentially tighten AECO because the counter to that is there just seems to be a lot of gas behind pipe. And so do you actually get the price response with the LNG pulp?
Michael Rose: Yes. We think we will. I think Jamie outlined that we really don't think there is a lot of gas behind pipe right now. We think we're seeing pretty much everything that's available on stream at this point. We expect another Bcf plus of intra-basin demand when we get cool weather. We're not cold at all yet here, but that is coming in the second half of November. You've got another 1.2 Bcfs yet to come from LNG Canada when they get Phase 1 and both trains fully on stream. And I think we're eyeballing Q1 of for that. And you still have, although, as I mentioned, for a few days here, the West Gate is fully open, but that's an extra 550 million a day that's still being backed into the basin. That's going to go away when the maintenance is done at the end of November. So in aggregate, you're well over 2 Bcf a day flip. And that's why Jamie was referencing it will be very instructive to see what the actual draws are from our storage during December because we think they're going to really drive a basis tightening once people figure out what's really happening. And as far as refilling from the supply side by our gas industry, kind of the best we seem to be able to deliver on an annual basis is that 0.6 to 0.7 Bcf per annum. So it's going to be close to 3 years to replace that sink. And a lot of that relates to getting on to the system and basin hydraulics and getting meter stations and the long queues that are there already before you can bring new gas on the system. You want to bring gas on the system today or in 2026, you had to be organizing your firm service 4 years ago.
Operator: [Operator Instructions] There are no further questions at this time. Please proceed with closing remarks.
W. Kirker: Thank you, everybody. We'll talk to you next quarter.
Michael Rose: Thank you.
Operator: Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.