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Good morning. My name is Sylvie and I will be your conference operator today. At this time, I would like to welcome everyone to Whitecap Resources Q1 2024 Results Conference Call. [Operator Instructions]I would now like to turn the call over to Whitecap's President and CEO, Mr. Grant Fagerheim. Please go ahead, sir.
Well, good morning and thanks, Sylvie. Good morning, everyone, and thank you for joining us. Here with me are 5 members of our management team. Our Senior Vice President and CFO, Thanh Kang; our Senior Vice President of Production and Operations, Joel Armstrong; and our Senior Vice President of Business Development and Information Technology, Dave Mombourquette. We also have with us today, Joey Wong, our Vice President of the West Division; and Chris Bullin, our Vice President of the East Division joining us.Before we get started today, I would like to remind everybody that all statements made by the company during this call are subject to the same forward-looking disclaimer and advisory that we set forth in our news release issued yesterday afternoon.I'm happy to advise that we are off to a great start in 2024 as a result of the collaborative efforts of our dedicated staff. We've experienced our most active quarter in our Whitecap history, running 15 rigs at our peak and spreading 96 gross wells.First quarter production averaged just under 170,000 BOE per day which was also the highest quarterly production since the inception of Whitecap 15 years ago and was over 6,000 barrels a day above our internal forecast of approximately 163,500 BOE per day. Meanwhile, in the first quarter, capital spending of $393 million was below our internal forecast of $425 million.Production outperformance has come from both our East and West Divisions, which Chris and Joey we'll talk to shortly. Of note, in the quarter we completed and commissioned our 20,000 BOE per day battery at Musreau in Northern Alberta. This was the largest facility and pipeline project Whitecap has undertaken to-date.Special thanks to the team for their exceptional work from planning and design through execution. The facility was completed approximately 2 weeks ahead of schedule and 10% below budgeted AFE costs. This is an important milestone for us as we reach the development phase of this liquids-rich Montney asset.We're very pleased to advise that with the continued outperformance in our East and West Divisions, this has given us the confidence to increase our 2024 annual production guidance to 167,000 BOE to 172,000 BOE per day, which is up 2,000 BOE per day from our previous guidance, with no change to our capital budget of approximately $1 billion. Also of note, as provided in our press release, Whitecap is hosting our inaugural Investor Day on June 11 from 8:30 a.m. Mountain Time virtually.As we have now owned the XTO assets for just over 1.5 years, we are looking forward to showcasing the technical depth of our team along with the strength of our inventory both in the East and West Divisions and the long-term sustainability and profitability of our business.I'll now pass the mic on to Thanh Kang to discuss our financial results.
Thanks, Grant. We generated $384 million of fund flow or $0.64 per share in the first quarter, which was used to fund the first quarter capital program of approximately $393 million. Q1 is our most active with the highest level of capital spending in the year. With spring breakup underway in Western Canada, we will be generating significant free funds flow in the second quarter as our capital spend in the quarter is expected to be only $200 million to $250 million.Although WTI prices in the first quarter were flat to the fourth quarter, Canadian light oil differentials were relatively wide at over $8.50 per barrel, resulting in short-term funds flow impact that has since normalized, with strip prices implying tighter differentials once the Trans Mountain expansion pipeline comes online in the first week of May.Natural gas prices continue to be challenged and the outlook does not materially improve until LNG Canada Phase 1 is commissioned. We anticipate Western Canadian and specifically AECO prices to improve upon startup of the facility, diverting significant volumes to Coastal GasLink, which should alleviate pressure on existing pipeline systems to better absorb downtime for other restrictive events.Liquids pricing drives the economics of both our conventional crude oil assets as well as our unconventional development, given the high condensate yields. However, improved natural gas prices would be material to our free cash flow generation as we produce approximately 370 million cubic feet per day of natural gas. From a cash cost perspective, our first quarter results are generally in line with our expectations.Operating costs per BOE were slightly higher at $14.27 per BOE compared to the fourth quarter of last year at $13.41 per BOE due to the extreme cold weather in January impacting operations. The royalty rate in the first quarter was 16.8% compared to 17.9% in the fourth quarter of 2023, primarily due to lower realized oil and NGL prices.Cash tax expense of $2.51 per BOE was significantly higher than $0.24 per BOE in the fourth quarter of 2023. Cash taxes are calculated based on forward strip prices at the time of calculation and are trued up or down based on actual prices for the year, so there will be some volatility in this estimate as we move through the year.We paid $109 million of dividends during the quarter or just over $0.18 per share and feel very comfortable with the sustainability of the dividend longer term. As we generate free fund flow in the second quarter, we will look to focus on share buybacks to enhance shareholder returns.Our balance sheet is in excellent shape with debt to EBITDA of 0.7x. We have $200 million of private placement notes maturing May of this year. And given our significant liquidity, we anticipate we will be paying this off with our bank revolver which will result in total credit capacity of $2.9 billion.I will now pass it off to Joey for more remarks on our West Division results.
Thanks, Thanh. Our West Division had a very solid quarter, with production outperformance being complemented by the commissioning and startup of our Musreau Battery. As Grant mentioned, this was done both ahead of schedule and under budget. This is the largest facility build that we have done as a company and while we are still making our way through the early stages of volume throughput, we are very pleased with the uptime and capabilities that this facility provides for us.We have completed and tied in our first 8 wells at Musreau and are bringing them on stream to our new battery in a staged approach with initial production results exceeding our expectations. We plan to bring on a total of 16 wells at Musreau in 2024.As mentioned, development of Musreau was high on the priority list after the XTO acquisition was completed and early-time results are supporting our view. At Kakwa, our 321-B 3-well pad is performing in line with the adjacent 226-B 3-well pad after 90 days on production, which is 20% above our initial expectations for development, utilizing 6 well per section spacing.Based on the production results and the technical data obtained from these 2 pads, we believe that the economic return profiles of this area are improved using this updated spacing strategy. We are evaluating the application of this spacing strategy across our other unconventional Montney and Duvernay assets and while the technical analysis may conclude that this specific strategy may be limited in its application, the success of individual well design modifications is increasing our confidence in our approach to longer-term development planning.That approach is to tailor individual well design inputs based on our assessment of localized geological and reservoir parameters and how our completions will interact with those parameters. Those inputs might include inter-well spacing, lateral placement, completion parameters and production practices.Ultimately, our efforts are focused on yielding incremental improvements in our already strong economics and enhancing the value of our asset base. In Lator, we are pleased with the continued outperformance of our 2-well pad. This pad, along with the 2 wells that will be drilled later in 2024 will provide key inputs to the design of Phase 1 of our infrastructure solution for this catchment area.We are making good progress on the initial design stages and expect to have an update on this front later this year. At Kaybob, our first 7 Duvernay wells drilled since the XTO acquisition are continuing to outperform our initial expectations by 22% and we are very pleased with the results to-date.As mentioned, our follow-up next 3-well pad at 1134-B with 4,200 meter laterals has been rig released with on production dates expected at the end of the second quarter. Following up on the 1134-B pad, we have just commenced drilling on a 5-well pad at 1114-B.Lateral lengths will range from 2,800 to 3,600 meters depending on the lateral length of offset wells to the north. As part of our ongoing well design initiatives, we plan to land laterals with a 15 to 20 meter vertical offset. This is otherwise referred to as multi-benching or a wine rack approach within the Duvernay formation.This is done in an effort to both increase our total contacted reservoir and limit interaction between individual wells. Upon success, this has the potential to increase both our inventory and per well EURs in the area.I will now pass it on to Chris for his comments on the East Division.
Thanks, Joey. Record activity levels and subsequently record production were the main themes in our East Division for the first quarter. Our predominantly light oil assets in this division reached 100,000 BOE per day in late March through a combination of both base and new well outperformance. From a new well perspective, we're particularly excited for early time well results from our 4 Glauconite wells that came on production during the quarter.The Central Alberta team did an exceptional job executing on our 3-well [ 5017 ] pad at [ Westward Ho ], which targeted 2-mile lateral lengths in a technically challenging area due to faulting. These wells are approaching 30 days on production and are significantly outperforming our type curve on both total production and liquids rates based on early-time data.The fourth drill is fully bound 1-mile infill well, with early-time results outperforming our standard type curve for the area. The early results from all 4 wells brought on during the first quarter are encouraging for future inventory upside potential. Our Glauconite program continues to exceed our expectations and provide meaningful volumes for the division. As mentioned in the press release last night, our well results in eastern Saskatchewan are showing outperformance based on early-time data.We are also encouraged by Saskatchewan government's recent multilateral royalty program. 35% of our Eastern Saskatchewan 2024 program already utilizes triple-leg laterals and given the new incentives, we will evaluate our second half and potential 2025 drilling programs to see where we can add lateral legs to our planned single and dual-leg wells.At present, we have 3 rigs active in Central Alberta on spring breakup pads. Two are focused on the Glauconite while the third is drilling Cardium in West Pembina. In Saskatchewan, we are monitoring breakup conditions and our team is looking forward to getting back into the field and building off our strong first quarter.With that, I will turn it back over to Grant for his closing remarks.
Thanks, Chris. We feel that the outlook for Canadian energy is very positive as long-dated infrastructure projects are beginning to come online and more broadly speaking, capital discipline within the energy sector and increasing demand for oil are supporting global crude oil prices.We are in an exceptionally strong position with a large defined drilling inventory and believe that our team has the technical expertise, creativity, and drive to extract significant value from our asset base, leading to long-term sustainability, increased profitability and ultimately healthy returns for shareholders well into the future.As mentioned at the start of this call, our increased production guidance reflects our strong start to the year and we look to build off this momentum as we move through the balance of 2024. On current strip prices, we forecast funds flow of $1.7 billion, resulting in $700 million of free funds flow after capital, of which $435 million will be returned to shareholders through the base dividend and further enhanced with share repurchases under our normal course issuer bid.With that, I will now turn the call over to the operator Sylvie for any questions. Thank you.
[Operator Instructions] And your first question will be from Dennis Fong at [ CIBC World Market ].
My first one here is maybe directed to Thanh. I was just hoping to understand how you think about your current capital structure. Obviously, you've made a lot of progress with respect to improving aggregate leverage and I was wondering, can you quantify maybe where an ultimate leverage level, or maybe an optimized capital structure happens to be and maybe what factors influence the way you think behind that debt level?
Yes, thanks for that question there, Dennis. Yes, I think when we look at an optimized run rate level, we look at everything, our dividend as well as our cash flows down to $50 WTI and $2 gas. And so what we'd like to be is less than 1x debt-to-EBITDA at that low commodity price environment.So a run rate, call it $1.3 billion, would get -- would allow us to achieve that. Debt at the end of the first quarter was $1.5 billion, with the active drilling program that we had. But based on our forecast, we're expected to be about $1.2 billion by the end of the year there.So it puts us in a really good financial position, where we've protected our shareholders down to a low WTI level, gives us lots of liquidity to be able to execute on our program. The dividend is sustainable down to $50 WTI and it provides us an opportunity to execute on potentially a larger share buyback as we think about the back half of 2024 here.
Great. I appreciate that color. Maybe shifting focus and thank you for highlighting some of the factors you're focusing on to drive stronger well results, especially at Kakwa and potentially across the West Division acreage. I was just curious as well, how quickly do you view the application of revised completion or development techniques to new wells? And when, if successful, can we potentially see some of the, we'll call it the fruits of this work?
Yes. Dennis, Joey here, I'll take that one. I mean, the short answer is you'll get some initial indications upon completion of how the fracs are potentially interacting with each other or not. So that would be the first check mark we look for would be kind of on day 0. It's a process of monitoring it through, I'd say, the first kind of 6 to 12 months. And we'd hope to start to see deviation from alternative development profiles, or I guess, legacy ones in the area.So you'd start to feel pretty comfortable around somewhere in that 6 to 12-month time frame if things are working out. In terms of how we roll that out in our program, we would expect things that we do this year are very likely to impact the next calendar year in terms of capital activity. So pretty quick turnaround.
Next question will be from Jeremy McCrea at BMO Capital Markets.
This is actually a bit of a follow-up question to Dennis here. Just you talk about some new learnings that you picked up at Lator. I'm wondering if, Joey, you can be a little bit more specific maybe in terms of what that looks like, what you want to do for the next round of wells. And just with a lot of the improvements, a couple of these wells coming in better than expected, how do you guys look to shift CapEx for 2025 to the East versus the West here?
Yes, I guess specifically, Jeremy, as it pertains to Lator well design, our 2 wells are single-well pads. And they serve a dual purpose to both delineate and kind of spread out our coverage in terms of what we know about wells. So if we're talking about things like inter-well spacing, or benching or things like that with our program, we're not going to be assessing that with our wells.That said, you identified offsetting wells. There is quite a bit of activity that we are chewing through as we speak, as every month turns over and new bits of data come available to us. So given that our full development in the area is a little bit further out, we'll be assessing that as time goes forward.
I'm just going to take on -- it's Grant, Jeremy, just take on the second part of your question and that was about for 2025, do we look to shift capital from East to West or West to East? And that isn't the case. What we'll look to is each of the areas, respectfully, our Eastern Division is providing some very, very, very good results as well.Chris had talked about some of those in the Glauconite formation, but we also talk about Eastern Saskatchewan, Western Saskatchewan. So each of the divisions we'll look to most profitable assets that we possibly can advance forward. And our Western Division is very much providing a lot of growth for us at this particular time.So we'll continue and methodically advance our technical advancements there. But also, the Eastern Division is equally as important for what they're doing in all other assets. So from our perspective, 2025 is a long ways out, but we'll start looking forward to making those plans for '25, '26 and '27 here as we move through the summer months.
Just maybe a couple of follow-up questions there. If you're continuing to see these wells come in better than your expectations, can we expect to see more revisions up in guidance here as the year goes through? And then just before, I think it's on probably everyone's mind the Chevron Duvernay package, maybe just a quick comment on what you guys are thinking of M&A here this year as well?
Yes, just regards to guidance. I mean, if we can continue to perform as we have performed, which are very positive, we also have to go through the summer months where we're anticipating the unanticipated, I guess if I can use that terminology, with the potential for downtime that we're not expecting. So at this time, we're not projecting any further increases to our guidance.But we can see how not only operational performance, but how the -- we'll talk about how the environment treats us from an overall perspective. To the -- your other comment on acquisitions, I mean, Chevron packages is available. We're looking for smaller-scale acquisition activity to complement in and around our existing assets. Yes, the Chevron packet offsets our Kaybob activity.But it is a larger package that we wouldn't be on our front foot on. Smaller components of it we'd be interested in. But more importantly, what we're looking at is how do we improve the profitability and sustainability of our existing assets today, so from what we'll call our beachheads out?That's the way we'll look at advancing forward. We do not need a huge amount of incremental inventory. We have a large inventory base. We're fortunate to have that. So we would have to explain to our shareholders the reason for doing that would be increasing profitability and sustainability for the longer term.
Next question will be from Anthony Linton at Jefferies.
Maybe just on the 5-year plan and particularly within the West Division, can you just remind us where you stand from an infrastructure capacity standpoint and plans for future build-out? And then with the cost savings on Musreau, any key learnings that could be essentially applied to that build-out?
So yes, what we're looking at at this particular time on the Western side, where we're looking to grow our business in excess from what was 100 -- or which was 70,000 BOE per day to over 110,000 BOE per day will require incremental infrastructure. So what we're looking at is how best to place that. We're doing a lot of engineering analysis at this particular time.And how best to finance those is always under consideration as we advance forward. So because the pace may be higher than 110,000 BOE per day over the 5-year period of time that we're projecting, but it's all going to be dependent upon the build-out process that we do have infrastructure, whether it's with our capital, or third-party capital coming in to assist us.
Got it. Okay. And then just on the cost savings at Musreau, any -- with 10% under budget, any key learnings there that you could apply to that build-out?
I'm going to let Joel talk to that a bit, but other than to say, I like it, keep it going. Yes. Joel said nothing specifically to add to that, other than they were on it right from the beginning through the planning process, through last spring and summer and the execution went extremely well.
I think with the next phase, you'll see cost savings on the drilling side, too. So we're just getting warmed up there.
Okay. Got it. And then maybe just switching gears on your -- just wondering if there's any -- when we might be able to expect an update on your new energy opportunities?
Yes, the -- right now what we're being delayed with is not on our own fruition. It's with government -- challenges we're having with the governments finalizing what their what we'll call the investment tax credit market is looking like and how quickly they can advance through that at the federal level and provide some guidelines for us to utilize.So our timelines would have been that we'd be up and operational this year, with some of our incremental carbon capture projects, but we're waiting on finalization of what the policies come forward from our federal government.
Next question will be from Patrick O'Rourke at ATB Capital Markets.
The rundown questions have been fairly comprehensive so far. I just want to first unpack in terms of some of the well changes that you guys are making here and what the opportunity is. You're talking about potential on cost savings and you've increased the guidance here because production is outperforming.So just wondering, looking forward as you're thinking about these things and thinking about maximizing the value of the asset, is the opportunity here more so on the cost side? Is it on the IP side, or is it ultimately on the recoverable resource side? Just help us understand what the biggest lever is going to be for Whitecap going forward?
Yes, it's Joel here. I guess a couple things really. We're just trying to drive our capital efficiency as our number one objective, whether that's increasing lateral length, changing wellbore construction design, whatever it takes to take us to that next level of capital efficiency.
Okay. And maybe just shifting gears again here real quick, I noticed that in terms of the risk management, the marketing, you added a little bit of hedging on the oil side, largely flat on the gas side. Just curious how you're thinking about marketing the gas, as you have increasing gas volumes, any changes there? And then your outlook in terms of risk management, how you'd look to sort of hedge things heading into 2025, both on the oil and gas side?
Yes, it's Thanh here. Thanks for that question there, Patrick. So the way that we think about our hedge book is want to make sure that we are fully funded down to $50 oil and $2 gas, which means that we can maintain our level of production as well as fund the current dividend there. And so with our hedge book currently at about 17% for this year, as I mentioned, we are fully funded, both dividends and our maintenance production level.As we think about 2025, we'll continue to layer on the positions. Obviously, the oil is what drives our cash flows, right? And so we'll be focused on that. And whatever we hedge on the oil side, you'll see us hedge commensurate on the natural gas side as well. So we're targeting somewhere in that 30%.We're about 16% right now in 2025 for us to run a fully funded program. So you'll see us incrementally hedge those positions as we move through 2024 here. On the natural gas pricing, we do produce 370 million a day of natural gas. Majority of that right now is AECO priced. But we are looking -- our marketing team is looking at price diversification over the medium to long-term here.We are part of the Rockies LNG, 100 million a day. So part of that will be diversified, as that gets FIDed as we move forward here. And we are looking at, both on the physical and the financial side, to potentially move away from AECO, whether that's Chicago pricing or NYMEX pricing. But ultimately in that 25% to 30% outside of AECO would be our objective.
And at this time, Mr. Fagerheim, we have no other questions registered. Please proceed.
Thank you, Sylvie. Once again, we appreciate you for taking the time and interest to listen to this call today. Again, 2024 is off to a great start and we look forward to discussing our technical and operational performance at the upcoming virtual Investor Day on June 11. Wishing each of you all the best through these spring and summer days. Thank you.
Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending and at this time, we ask that you please disconnect your lines.