Good morning, ladies and gentlemen, and welcome to Murphy Oil Corporation Third Quarter 2025 Earnings Conference Call and Webcast. [Operator Instructions] I would now like to turn the conference over to Atif Riaz, Vice President, Investor Relations and Treasurer. Please go ahead.

Thank you, Lucy. Good morning, and welcome to our third quarter 2025 earnings conference call. Joining me today are Eric Hambly, President and CEO; Tom Mireles, Executive Vice President and CFO; and Chris Lorino, Senior Vice President, Operations. Yesterday after market close, we issued our third quarter earnings release, a slide presentation and a stockholder update. These documents can be found on Murphy's website and we will reference them today throughout our call. As a reminder, today's call contains forward-looking statements as defined under U.S. securities laws. No assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, please refer to our most recent annual report filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements, except as required by law. Throughout today's call, production numbers, reserves and financial amounts are adjusted to exclude noncontrolling interest in the Gulf of America. I will now turn the call over to Eric for opening remarks.

Thank you, Atif, and thank you, everyone, for joining us this morning. Consistent with our approach last quarter, we released our quarterly stockholder update last night alongside our earnings release. This morning, I will share a few high-level insights and perspectives on our business before we move into Q&A. I'd like to start by thanking our employees for delivering strong operational performance in the third quarter, exceeding the high end of our production guidance for the second quarter in a row. We achieved total production of 200,000 barrels of oil equivalents per day and oil production of 94,000 barrels per day, underscoring the strength and potential of our assets. It's always good to have a quarter where we deliver strong operational performance, both on the production and cost fronts, and we did exactly that in the third quarter. Operating costs in the quarter averaged $9.39 per BOE, 20% less than in the prior quarter. In the third quarter, capital expenditures totaled $164 million, which was below our guidance. While a large part of that lower CapEx was due to timing, it also reflects our ongoing efforts to drive capital efficiencies across our business. On the international development and exploration front, we made significant progress in the third quarter. Our Lac Da Vang (Golden Camel) field development is progressing on track. And in fact, we started drilling our first development well earlier this week. This is a major milestone marking our first development in Vietnam. I commend the team for continuing to execute this project safely and ahead of schedule in collaboration with our multiple local and international partners. Our Hai Su Vang 2X Appraisal Well was spud in line with our plan and Civette, the first of our 3-well exploration program in Cote d'Ivoire is also on track to be spud before year-end. This quarter, our exploration teams are working very hard at exploring and appraising prospects across 3 continents, testing gross resource potential of over 1 billion barrels of oil equivalent. These projects showcase Murphy's international expertise, reputation and partnerships, key differentiators that position us as a partner of choice for global exploration and development. We look forward to sharing the results from our exploration and appraisal program with you in the coming months. As we assess our operational plans for 2026, we are closely monitoring the commodity markets. We remain confident that our strong balance sheet and flexible multi-basin portfolio will allow us to manage near-term volatility while staying on track to achieve our long-term goals. Looking ahead, exploration continues to play a significant part in the Murphy story and we're encouraged to see a renewed focus in the industry on the need for exploration and conventional resources to meet global energy demand. With a robust portfolio of assets and decades of expertise, we are well positioned to capitalize on the opportunities ahead. That's a very brief summary of our quarter and key catalysts for our business and we will now open the lines up for questions.

[Operator Instructions] With that, our first question comes from the line of Arun Jayaram with JPMorgan.

Eric, I was wondering if you could start a little bit around your exploration program in West Africa. Maybe some details on the Civette well, which you mentioned should spud by year-end. And it looks like you've re-sequenced the program to include a different prospect for your third exploration approach. I was wondering if you could just give us some more color around that program.

Sure, Arun. We're really excited about our Cote d'Ivoire exploration program, which will start drilling before the end of the year, likely spud Civette in December and that should put us in a position to have some results to discuss at our January fourth quarter earnings call. The following 2 wells in the program likely not have results to report until later in the first quarter or possibly into the second quarter of 2026. The Civette prospect is very similar in terms of the geology to the Calao discovery from the Murene-1X well Eni announced in the second quarter of 2024. It's the same type of geology, just a slightly shallower interval testing highly prospective to us, Santonian-Turonian interval which we're really excited about. We think as we released in our slide decks in the past, the potential is significant. And the reason that we are really excited about it is it has the potential to be quite large with a mean of over 400 million barrels, upside of 1 billion barrel range and we're able to test the wells. Our program of wells are going to be kind of in the $50 million to $60 million gross range. So really excited about it. It's definitely in the right neighborhood. There's been a lot of recent success from Eni in the area and it's similar looking geology and we're pretty excited about it. [Indiscernible]. So as we've kind of continued to work through our reprocess seismic data set and kind of mature our assessment of the prospectivity, we decided to pivot from drilling Kobus to Bubale. And the reason we did that is we think that it offers a lower cost to test and lower risk or a higher chance of a discovery and also a very large resource range. So we're pretty excited about that. The Kobus discovery is definitely still something that's out there and it might be the subject of follow-on exploration. Obviously, with some success, it would encourage us even more. It is a different play type than Kobus, one that we think has a higher chance of being successful and that's why we made the switch. So there's nothing wrong with Kobus, just that we think that Bubale is a slightly better and we're prioritizing sort of our top 3 exploration tests in the blocks. Those are the ones that we think are the most compelling near term.

Makes total sense. And just maybe a follow-up. Obviously, you're drilling one of the more important appraisal wells at a very long time in terms of Murphy. Can you give us some of your key objectives? And I know you've shared with us the location of the appraisal well in Vietnam, but maybe give us some thoughts on what you're looking to test at the HSV field.

Sure. Yes, it's a good question. The main purpose of the HSV-2X well is to determine what the lateral continuity of the reservoir is. So away from the discovery location, what is the makeup and content of the sand in the major discovered reservoirs to potentially test for a thick in the pay section and really critically determine if we can, where the oil water contact is. So we believe the location that we're testing has the potential to prove a thickened section in the primary reservoir of the discovery and also prove the known oil column deeper. And that's the main objective of the appraisal well, which the whole point is to determine what is the -- tighten the range of resources and figure out how large is the field and help us start to plan field development. We need to know where the oil is so we know where to put the development wells. And this is the first of what may be more than one appraisal well to determine how large the field is and how to optimally develop it. But this one has a significant impact in that the major discovered reservoir that we flow tested that we announced earlier this year, we're hoping to prove a deeper oil column with that and potentially expanded thicker section.

Great, Eric. We'll enjoy well watching because you have a lot of interesting things that you're testing over the next 3 to 6 months. Appreciate it.

And the next question comes from the line of Neil Mehta with Goldman Sachs.

We're obviously working through a choppier macro right now and there's a lot of reasons for long-term optimism, but of course, there's some reasons for near-term caution. So just talk about your down cycle playbook and how you ultimately use a period of potential commodity weakness to make the business better a couple of years out.

Great question. Obviously, we're paying very close attention to what's going on with commodity markets, watching both oil and gas. We're still working to put together a plan for our 2026 budget, which we'll discuss like normal in our fourth quarter call in January. We're factoring in things like what do we think will happen with oil price in the first part of the year versus potentially the later part of '26 heading into '27. We're trying to develop a plan, not just for the year, but a multiyear plan that supports our strategy that balances near-term production and free cash flow with investing for longer-term resource additions, primarily for our offshore business. We do have significant flexibility in our capital program. We could run quite a bit smaller onshore program for sure. In our offshore business, there are a few things that I think we're likely to do in almost all oil price scenarios. There are things that we have a lot of flexibility to have an altered program. I think the things that are likely to be a little more sticky for us and that we probably choose to do, our Vietnam appraisal program that we're doing now and our Cote d'Ivoire 3-well program, I think you could see us doing those in most cases. You would have to probably have a very, very low oil price where we decide to alter those plans. The other one is our Lac Da Vang (Golden Camel) field development. It's something that we likely see through to conclusion of the first phase in most oil price scenarios. As we talked about last quarter, I'll kind of reiterate, we're very comfortable with our sort of base plan in line with our communicated multiyear range of CapEx. If oil price is $60 or so the longer that we think we'll see a sustained oil price that might be lower like, say, $55 or lower for a long time, we might start to get more aggressive in altering and lowering our capital plan. And again, we have quite a bit of flexibility. Obviously, the sooner we start making changes, the more we could affect next year CapEx. But we feel like we're well positioned. We also feel like we have a very strong balance sheet. So we're able to kind of -- if we wanted to, we could lean into a little bit of invest through the cycle. But like I said earlier, we're going to be pretty cautious around protecting a strong balance sheet, investing with kind of a balance of short term, medium term, long term. And I think we've acted in the past with quite a bit of discipline and you can expect to see that from us going forward.

Yes, very clear, Eric. And then that brings up the follow-up, which is as we think about the '26 CapEx, the midpoint of your guide this year is $1.21 billion, of which offshore is 36% of the balance is outside of it. And so just how do you think about the buckets of CapEx as you go into '26, recognizing we'll get more color early next year, but what are some of the moving pieces as we anchor 6 versus 5?

Very good question. Again, we're still working the details. I'll give you kind of directionally that is kind of provisional. I think with our active program exploring in Cote d'Ivoire, you might see a little more spending from us in exploration than this year or past years just by a little bit. In terms of onshore spending, we'll probably have a slightly lower capital program in Tupper and Eagle Ford than we had in 2025. In offshore, we have a really compelling set of investments to pursue with strong returns and very low breakevens. One of which we've highlighted is the Chinook 8 well, which is a development well in our currently producing Chinook field that we expect to bring online in the second half of the year. And we think it will have a gross oil production rate somewhere in the 15,000 barrel a day range. So those are very compelling investments that we're likely to do. The rest of the details around exactly what the rest of our offshore program and do we fine-tune our Eagle Ford program with potentially lower commodity price, that's something that we're going to be looking at and paying attention to and kind of thinking about as we head into next year. I would say, overall, it would be reasonable to expect us to have a capital program next year of a similar scale as we've communicated in the past, which is a $1.1 billion to $1.3 billion range.

And the next question comes from the line of Carlos Escalante with Wolfe Research.

First of all, congratulations, quite the turnaround on sequential quarters. So congrats on that. If I may, I'd like to ask my first question on your operational improvements thus far this year. So maybe you can perhaps frame and quantify how the improvements in both your Eagle Ford and Montney, how that success has translated in terms of corporate breakeven. And I know and I realize it's a small piece of your portfolio, but just wonder how that is manifesting in your underlying breakeven.

Great question. Just high level, I'm very impressed with and very happy with our team's ability with a fairly limited onshore program to be able to continue to make improvements in our capital efficiency, both Eagle Ford and Montney, particularly, where in the second quarter and third quarter wells, we saw some of our strongest performance ever. Initial rates, 90-day cum oils, 90-day cum gas for Tupper, all been amongst some of the best wells we brought online. That's been through a combination of various things. In many places, we're drilling longer laterals, which we're able to improve our drilling targeting, our completion styles, we adjust kind of the completion design for each specific area to try to optimize what's going on there. Our flowback strategies have been really enhanced. And it's just driving a really strong outperformance. I think we've highlighted that in some cases, we're seeing production rates in terms of the first few month production that are 50% to 100% above what historical performance is. So really strong. In our Tupper asset, we -- in 2025, we've used a completion design that had significantly higher proppant loading and we think that's working for us and will likely feature that going forward. What I'm also really proud about is that we were able to pump better fracs with CapEx neutral or, in fact, some CapEx savings across our program. So we're doing things that are not just spending more money to get more performance. We're actually getting better performance with equal or lower investment, which is really good for generating cash flow and to your point, what our breakevens are. In the stockholder update, we highlight just how low some of the breakevens are for the Catarina program we delivered. Obviously, when you can have breakevens that are $35 or less and sometimes even in the $20s, that's awfully strong. So really happy with how all that's going and it's led to significant performance -- outperformance and I think it's durable in the sense that the remaining inventory we have to drill, we're going to keep doing the same sort of stuff and we should continue to see that kind of outperformance as we progress the rest of our onshore program. In offshore, I'm really happy with the turnaround. We had a tough year, 1.5 years with wells offline in the Gulf requiring workovers. We progressed through that. I think we're in a good spot. We did have a production beat for the quarter even when you adjust for no storm downtime in the Gulf, we still exceeded even beyond what the storm downtime provision was with really impressive work by our team to have very low downtime in our operated major facilities, really top world-class performance in terms of our operating performance there.

That's very, very helpful color, Eric. And then for my follow-up, if I may follow up on Arun's question on West Africa. It looks like most of the historical exploration effort in the region has been done along the Upper Cretaceous with some success, but it was really Eni's Baleine and Calao discoveries, at least in our view, that have enlightened this new wave of excitement in the emerging deeper Albian Santonian intervals. Would you guys concur with that in terms of is your seismic effort consistent with exploring that deeper potential as well as the Santonian-Turonian interval that you mentioned, Eric?

Yes, it's a very good question, Carlos. So what has happened in this Greater Tano Basin area is after the success of Jubilee going back a decade, pretty much everybody drilled the same look-alike prospects as Jubilee until Eni did something different. And I would say it's a fair characterization that we see potential in the largely untested slightly deeper intervals. And that's what we're pursuing in most of our prospects here that we're testing.

And the next question comes from the line of Paul Cheng with Scotiabank.

Two questions. One, I want to go back into the 2X appraisal well that you're going to drill in Vietnam. If it is successful, Eric, can you tell us that is that going to be sufficient for you to set the development plan or that you think you actually would be better off because it's a large discovery? So you're better off that to drill an additional appraisal well that to really get a confirm and whether that you will go with a -- given the size that do you think that a early production system will work better and then that you will have a full development? Or that you will just go ahead with a full development? And trying to see that, I mean, what's the next step in 2026 after this -- after the completion of this well is going to look like? This is the first question. The second question is on the impairment charge. You're saying that just because of a unfavorable disproportion expense allocation so that you write down the value in there, is that have any implication for your other well or other fields in the area?

Okay. Paul, on your first question, we're drilling the Hai Su Vang-2X well. And I mentioned earlier on the call kind of the purpose of what we're trying to accomplish. So the potential for future appraisal beyond this is somewhat dependent on what we find in the 2X well. If we find a deeper oil column than proven in the discovery well, we're likely to have other appraisal wells to kind of determine where -- how much oil there is. If we drill just below the currently low proven oil in the Hai Su Vang-1X discovery well and find water level, then we may be less likely to pursue another appraisal well. So it somewhat depends on what we find. What we will do, what we typically do is sort of learn as we go and on a kind of point-forward basis, determine what do we need to know about the field to move forward to have confidence that we have it described appropriately with an ability to commit the capital to go develop it. So I think it's likely that we will have an additional appraisal well beyond the 2X, but it will be somewhat dependent on the results that we have and what we still have unknown about the field as we go forward. If we find only oil in the 2X well, it could imply that there is a deeper oil water contact than we test in the 2X and we'll likely go find it or try to find it with additional appraisal wells. One of the thing, our appraisal program is pretty efficient here. These wells are not too expensive to drill to find out. So we're able to do that quite efficiently. Just briefly on the impairment [indiscernible]...

Impairment. Can you tell us what is you guys leaning to us into the development concept at this point?

Sure. Yes, Paul. So -- and I didn't fully answer part of your question, I guess. We will try to do what we can to appraise the field kind of in the coming months and understand what we think the size of the reservoir is and how to optimally develop it. We will try to move forward to planning a field development plan and working with our partners and the government on that. And I would say we don't know yet because we don't know what we haven't yet determined, but we'd probably be looking at targeting final investment decision in 2027 and looking in a kind of a standard mode to producing Hai Su Vang in, say, around 2030, possibly earlier with an early production system. We're looking at all opportunities we can to efficiently develop the field. A conventional development of the field would be similar to our (Golden Camel) Lac Da Vang would be an FSO and a series of platforms, a main processing platform and wellhead platforms. There's also a possibility of redeploying an existing FPSO and doing some wellhead platform or subsea tieback type of opportunities. Those are all things that we're thinking about, looking out and we'll be trying to move as aggressively as we can to see first production with potentially early production system, but that's not something that's been particularly common in Vietnam. So that would be something we'd be sort of newly bringing to bear there. Before I move on to the impairment, did I address your question, Paul?

Yes. Very good.

Okay. On the impairment, we periodically review the projects in our portfolio and kind of reevaluate our plans of investment. In the Dalmatian field, we had planned to do 2 wells. And as we continue to study those and think about them, we saw that the operating expenses that those wells would be burdened with from the host facility that we do not operate started to look like they were really high costs. And that high cost made it look like they may not be the best investments to make. So with the current cost estimates, those investments in new wells would definitely clear our cost of capital, but they start to become less attractive investments compared to other things we would choose to invest in. So we decided in our 5-year plan in front of us to not invest in those 2 wells that were in our prior plan. When we remove that assumed revenue and reserves from our plan, it led to an impairment. The producing wells are doing fine. The impact of producing wells is really nothing. We just -- when you take the revenue and the reserves away from that plan, the future cash flow didn't compare favorably to the undepreciated book value, which led to an impairment. So there's no significant read-through to the currently producing assets or any other fields in the area. It's just we're choosing in our 5-year plan to invest in better investments.

Right. I think that's my question because you're saying that is related to a unoperated facility that the allocation of cost is higher. Do you have other assets that will have a potential impact or potential risk to that that will change your development outlook?

That's a good question, Paul. So we are fortunate to be in a position where we operate the host facilities for most of our production and the host facilities other than the one that Dalmatian uses that we do not operate have very low operating expenses. So the main nonoperated ones would be St. Malo and Lucius, which are very strong performing assets with very low operating expenses. The rest of our Gulf of America portfolio, effectively, we operate almost all of it and we're happy with our expenses there. It's really just this one Petronas facility that's late in life and experiencing escalating costs and the operator hasn't been too willing to do much to make the cost structure go lower, which is really the only sore point from escalating third-party operated cost issue.

And the next question comes from the line of Charles Meade with Johnson Rice.

I wanted to ask a question about your U.S. onshore guide for 4Q. And this might be down in the weeds a bit, but -- and specific to the Eagle Ford. And so that asset has really outperformed in 2Q and again in 3Q. And I understand you're not bringing any new wells on in 4Q. But even just for the PDP decline for that, your guide calls for that dropped by roughly 30% quarter-over-quarter. And I think you mentioned earlier in your prepared remarks that those recent wells that you brought online, I think I wrote down, you said those have been 50% to even 100% above type curve. And so I'm curious, is this -- that decline you're projecting for 4Q, is that the case where just internally, people don't want to underwrite the idea that these wells are going to continue to outperform the type curve? Or alternatively, is this something where you've already seen here in October, maybe early November, that those wells that had been 50%, 100% over the type curve have reverted to the type curve? Where do we fall on that spectrum there?

That's a good question. What I'll do is I'll give you my thoughts and then if it's insufficiently answered, I'll have Chris jump in and help me out here. What we have seen in Eagle Ford is really strong early production performance from our second quarter and third quarter wells. In the third quarter, more than half of our Eagle Ford production was from wells that we brought online in 2025 in the second and third quarter. So you're seeing more than half of our production come from essentially brand-new wells, which, as we know, shale wells, once they come off peak, they do have early kind of in the first quarter or so, a steep decline and they sort of shallow out over time. So what we are including in our guidance is an assumption that we will see significant decline in line with our kind of typical shale well performance that we see in Eagle Ford. Having said that, the early decline performance from our Eagle Ford wells is either in line or shallower than our historical decline performance from prior years. Even though our initial rates are higher, the decline rates early on so far have been in line or in some cases, shallower. So there's no big issue [indiscernible]. We are just modeling what we think will be a reasonable decline from what are really high initial rates. I'm really happy with the team performance. If you look at our Eagle Ford asset, roughly our fourth quarter guide is something like 5,000 barrels a day above our fourth quarter of '24. So that performance is continuing to be strong heading into the fourth quarter. It's just that the wells are -- the last of our new wells came online in July and we expect them to decline.

Hey Charles, just to add to that, when you're thinking about Q3 production, this is -- Eric mentioned, it's the highest new well production that we've had since 2019. So it is a little -- it is a big -- because we've outperformed so well, that's why you have more steep decline with the new wells versus the base. But looking forward, we've got such a bright outlook on the Eagle Ford wells and just continue to improve our long runway of Tier 1 inventory that just keeps getting better and better with lower breakevens.

Right, right. That's helpful. So success can bring its own different issues. Eric, I want to go back to Vietnam, but ask about your Lac Da Vang development. And appropriately, there's a lot of attention on the HSV. But can you remind us what the -- I know that there was already discovery that you guys came into, but can you give us -- remind us of the kind of the history of this field? And what I'm really curious about is if there -- when you're drilling your development wells there, is everything already very well characterized and there's no chance of a surprise? Or are there things that you're attuned to possible surprises or upside with this development drilling that's going to deliver more near-term volumes?

That's a great question. The Lac Da Vang (Golden Camel) field is one that has been significantly appraised up to the point prior to our investment decision. The initial phase development is targeting what is sort of the most appraised part of the reservoir. The second phase is sort of targeting, which will be wells online in probably '28, '29 -- sorry, drilling in '28 and online in '29. That part of the development has about half fairly well appraised and half kind of reaching out into the less appraised parts of the field. So near term, we're really comfortable that we're going to be developing something that we understand pretty well. Having said that, I think that there's always a little bit of uncertainty in terms of new field, how you expect wells to perform. So far, we continue as we learn more about the field to think it looks better and better versus worse and worse. And we'll certainly learn a lot from the initial development wells that we drill and we'll be trying to optimize our development as we move forward. But yes, it's -- I would characterize it as quite reasonably appraised, especially for what we're going to bring online for first oil.

And the next question comes from the line of Leo Mariani with ROTH Capital.

Wanted to ask a little bit about operating expenses. So very, very low here in 3Q, kind of certainly below the guidance range you guys had given. And now you guys are sort of kind of maybe guiding back up a little bit on OpEx in 4Q. So can you just provide some color there? Was it just like a total absence of workover spend in 3Q or something? Why did the number come out just a lot lower than it sort of has been? And is that sort of repeatable?

Yes. Great question. We did have some offshore workover spend in the third quarter. We talked about our onlines of kind of wrapping up our program. So we did have workover spend offshore, but it was of a little bit lesser amount than in prior quarters. The lack of large-scale offshore workovers helped improve our costs. We had significantly higher production across our onshore business and we lowered costs. In our Eagle Ford business, particularly, we're really focused on reducing the dollars being spent. That's mostly driven by field labor, maintenance costs, rental equipment, water handling, some work from our supply chain team to kind of renegotiate contracts and a real serious focus on optimizing the work that we do in the field through our remote operations center working with the guys out there in the field. Really happy with that. Those reductions in costs, which we kind of highlight in our stockholder update, those Eagle Ford reductions are durable and that really helped. What also really helped for the quarter was our record Tupper Montney production, has extremely low operating expenses. So when you blend in the sub-$4 operating expenses from Tupper, it really helps you have a total company fairly low operating expense. In the fourth quarter, we're guiding a $10 to $12 per barrel OpEx across the whole company. And the reason it's going up is that not because costs in terms of dollars are going up, but we are modeling a little bit less production. So the cost per barrel will likely creep up into that kind of range, which really is sort of a typical range for us on the long haul.

Okay. Very thorough answer. Appreciate that. And then just kind of on the sort of operational side. Obviously, gas prices have been quite low in Alberta in terms of AECO. Are you guys factoring in any kind of shut-ins that may have occurred in the guide for 4Q? Certainly, your Tupper volumes are down a decent amount. I know we haven't had really drilled a well in a while and you're getting some declines. But just what's the story with any kind of Montney shut-ins? How are you thinking about that? Is there some price level where it's kind of saved some of the gas? Or is it more just kind of keep the plant full?

Yes. What we're modeling in our fourth quarter production for our Tupper Montney is just typical decline from our base and new wells. And also, we're estimating a higher royalty paid in the fourth quarter compared to prior couple of quarters, driven by what we expect to be higher gas prices, pretty significantly higher. I won't get the numbers exactly right, but rough math I think AECO in the second quarter was like $0.64 an Mcf, and we're expecting a fourth quarter to be a little over $2, like $2.05, something like that. That may not be the exact numbers, but they're awfully close.

Okay. That's helpful. And then just real quick on the buyback. In this type of oil market, call it, $60 hasn't been obviously great for anybody. Are you guys basically kind of saying that probably don't expect much of the way the buyback if this kind of price sort of holds as you really kind of prioritize capital spend and the dividend?

I think it's fair to say with the free cash flow we have available with current commodity prices, we're less likely to be particularly active in share repurchase. Having said that, if we think there's a big dislocation in terms of our valuation and what our stock trades at, then we're not opposed to leaning into it as we've done in the past. Tom, if you want to add any color to that or that.

I think you covered it. It's something that we think of on an annual basis. We did in the first quarter start off with $100 million of share repurchases. But as Eric said, we're kind of keeping an eye on the price and oil price and likely not going to go too heavy on that in the remainder of the year.

And the next question comes from the line of Geoff Jay with Daniel Energy Partners.

I guess I was just going to follow up on Neil and Charles' questions from earlier. But when you talk about how there could be a smaller onshore program next year, is that potentially in response to a lower kind of macro or lower oil price environment? Or is it kind of a confirmation that you think that the outperformance that you've seen onshore is repeatable?

Good question. In our base plan, it's mostly the latter that, for example, our Tupper Montney, we kept that plant full for 5 months. The activity level we think it takes to refill and keep full from Tupper is less than this year because we are already coming in at a higher production level. In Eagle Ford, we've been guiding for many years that we anticipate using the asset to produce it in a 30,000 to 35,000 barrel a day range. And this year, we should be significantly higher than that, like around 37,000 for the year. And we think that the repeatability of our strong well performance of our new investments will be there. And so we think it will take a little bit less capital to deliver the same or higher kind of performance from our onshore assets. That's what's really driving it. My other comment earlier in the response to the call was if we see significantly low commodity prices, we do have flexibility and even pulling the capital spend in those assets down below what our kind of base plan might look like, which would have production impacts, obviously.

And we currently have no further questions at this time. I would like to turn it back to Eric Hambly for closing remarks.

I'd like to close by again thanking our employees for their hard work and dedication and our shareholders for their ongoing trust. Thank you, and this concludes our call.

Thank you, presenters. And ladies and gentlemen, this now concludes today's presentation. Thank you all for joining. You may now disconnect.