EXPAND ENERGY Corp (EXE) Q1 2023 Earnings Call Transcript

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to Southwestern Energy's First Quarter 2023 Earnings Call. Management will open the call for a question-and-answer session following prepared remarks. In the interest of time, please limit yourself to two questions and re-queue for additional questions. This call is being recorded. I will now turn the call over to Brittany Raiford, Southwestern Energy's Director of Investor Relations. You may begin.

Thank you. Good morning, and welcome to Southwestern Energy's First Quarter 2023 Earnings Call. Joining me today are Bill Way, Chief Executive Officer; Clay Carrell, Chief Operating Officer; and Carl Giesler, Chief Financial Officer. Before we get started, I'd like to point out that many of the comments we make during this call are forward-looking statements that involve risks and uncertainties affecting outcomes. Many of these are beyond our control and are discussed in more detail in the risk factors and the forward-looking statements sections of our annual report and quarterly reports filed with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance. Actual results or developments may differ materially, and we are under no obligation to update them. We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers. For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our website. I will now turn the call over to Bill Way.

Thank you, Brittany, and good morning, everyone. Thank you for joining today. At Southwestern Energy, our approach to sustainable value creation is clear and consistent: apply capital and cost discipline to a portfolio of advantaged assets in the two premier natural gas basins in the United States. We are focused on large-scale, core Tier 1 natural gas and natural gas liquids assets where we can leverage our operating and commercial strength, and safely and responsibly deliver lower-carbon natural gas to premium markets and generate superior economic value for our shareholders. Southwestern Energy's strong first quarter performance reflects the quality of our dual-basin scale, portfolio optionality and differentiated market access. We delivered above-target operational results with production at the high end of guidance and generated approximately $100 million of free cash flow to repay debt, consistent with the priority of debt reduction in our disciplined capital allocation strategy. Additionally, we are driving improvement in capital efficiency. In the first quarter, we continued to improve cycle times, yielding approximately 100 additional producing days during the quarter. Our strategic supply chain sourcing group has been successful in offsetting a portion of the inflationary cost pressure we expected at the beginning of this year. These efforts, in addition to our continued capital efficiency improvement drive, allow us to optimize our capital spend to align with cash flow while minimizing the impact to both production this year and the ongoing productive capacity of our business going forward. We are increasingly confident that the high service cost environment will continue to subside over the coming quarters, further strengthening our long-term free cash flow outlook. Despite the near-term commodity price weakness due to relatively high inventory levels following a record warm winter, we continue to see strong structural support for natural gas. On the supply side, U.S. production has remained essentially flat since late last year, and we have seen and expect to continue to see a decline in the gas-focused rig count and associated frac fleets. We believe that near-term activity reduction will result in lower natural gas production this year, further strengthening the longer-term fundamental outlook. On the demand side, with Freeport back at full capacity, LNG exports have returned to record levels of approximately 14.6 Bcf per day, supplementing persistently strong power burn. Flow assurance to markets of our choice is a critical pillar of our strategy. We have transportation agreements in place to deliver 65% of our total natural gas production to the growing Gulf Coast demand center, where we are currently the largest supplier of natural gas directly to LNG facilities at 1.5 Bcf a day. With Port Arthur LNG reaching FID last month, we now see nearly 9 Bcf per day of new LNG export capacity that is in progress and with some starting to come online as early as late this year. Our favorable access to the Gulf Coast positions Southwestern Energy to supply growing demand from both Haynesville and Appalachia. Given this positioning, we continue to receive strong interest and remain in active discussions for further LNG supply agreements, including proposals with internationally indexed pricing. As we shared in our guidance in February, we adjusted activity in response to lower near-term natural gas prices by removing capital from our program and increasing our level of liquids-rich development this year. Guided by our disciplined capital allocation strategy and our priority of funding development within cash flow, we continue to moderate our planned activity. These prudent adjustments are primarily focused on decreasing dry gas completion activity, including releasing a frac fleet in Haynesville, while maintaining our higher liquids-rich activity level in West Virginia and Ohio. This capital and operational flexibility highlights the strategic value of the optionality within both our development plan and our asset portfolio as well as the logistical agility of our vertically integrated business model. With this flexibility, we can quickly respond to commodity price signals throughout the year while preserving the productive capacity of our business going forward. The highly successful Haynesville integration and first-year results clearly support confidence in our ability to execute on the company's multiyear strategy to create long-term shareholder value. We continue to capture the tangible benefits of our larger-scale dual-basin portfolio and are well positioned to capitalize on the strong long-term fundamental outlook for natural gas. I'll now turn the call over to Clay for some additional operational updates.

Thank you, Bill, and good morning. The team started the year strong with first quarter production at the high end of guidance. Well performance and cycle time improvements in both Appalachia and Haynesville drove this outperformance. In total, we reported 411 Bcfe of net production, or 4.6 Bcfe per day, including 3.9 Bcf per day of natural gas and 107,000 barrels per day of liquids. We placed 36 wells to sales in the first quarter. In Appalachia, we placed 13 wells to sales with an average lateral length of just under 15,000 feet. This included 11 wells in the super-rich Marcellus and two in the dry gas Marcellus. Notably, we placed to sales our first pad of Monroe County, Ohio super-rich Marcellus wells, which are performing in line with expectations and confirming its competitiveness with our West Virginia super-rich Marcellus acreage. Since we acquired Montage in 2020, we have been successfully developing our Utica dry gas inventory. This year's addition of liquids-rich activity to the development plan in Ohio further illustrates the depth, quality and commodity optionality within our Appalachia portfolio. In Haynesville, the team placed 23 wells to sales, including 15 in the Middle Bossier and eight in the Haynesville with an average lateral length of approximately 8,200 feet. The strong initial production rates we saw in our first year in the Haynesville have continued with an average rate of 35 million cubic feet per day for wells placed to sales in the first quarter. On the operational efficiencies front, we are on track for our anticipated cycle time improvements. In our first year of operations in the Haynesville, we delivered 10% improvements to both drilling and completed footage per day and expect a similar 10% improvement this year. During the quarter, completion efficiencies drove accelerated turn-in-lines, resulting in three more wells to sales and additional producing days, which contributed to our production performance. In the first quarter, we saw positive signs of inflation moderation. Our team is actively pursuing cost reductions while maintaining supply security. Supply and demand for OCTG has balanced with cost and availability clearly improved versus last year. On the completion side, we've also seen softening on frac horsepower cost. With these tailwinds, we are confident in our plan to drive well costs down throughout the year, especially in the Haynesville. As Bill mentioned, we are optimizing planned activity to align capital investment with expected annual cash flow at current strip prices. As a result, we expect to invest near the low end of our $2.2 billion to $2.5 billion annual capital guidance range with cost inflation and capital efficiency improvements complementing activity reductions. We are delaying completion activities in our dry gas areas, including the release of an additional frac fleet in Haynesville beginning in mid-May and the release of a frac fleet in Pennsylvania earlier than planned. We expect these activity adjustments to result in second quarter capital spend slightly lower than the first quarter with most of the capital reduction occurring in the second half of the year. We have built flexibility into the program to add back this activity later in the year should prices or our expected cash flow improve. If this activity is not phased back in, we would expect to have 10 to 15 fewer dry gas completions and wells to sales than our current well count guidance. The completion delays are expected to result in a modest production impact in the second half of the year and a flatter quarterly production profile. Operationally, we have started 2023 strong and are focused on continuing to drive further efficiencies to optimize cash flow. Now I'll turn the call over to Carl.

Thank you, Clay. In the first quarter, we generated approximately $100 million of free cash flow. Together with seasonal working capital inflows, which typically reverse through the year, we reduced debt from $4.4 billion at year-end to $4.0 billion. Leverage improved to 1.2x, though we expect leverage to increase as we move through the year. In February, we redeemed all of our outstanding 7.75% senior notes due 2027, following through on our previously communicated debt reduction plan and path to return to investment grade. Turning to hedging, we have capitalized on the high level of contango in the strip by securing a base level of protection for 2025 using collars to preserve upside participation. We have also taken advantage of near record high volatility to convert collars to swaps and modestly raise our 2023 floor price. We are managing the business through the commodity price cycle to improve our financial strength and preserve our productive capacity to take advantage of the constructive longer-term outlook for natural gas. With that, please open the call.

At this time, we will take our first question, which will come from Charles Meade with Johnson Rice.

Bill, the question for you: could you give us some insight into how you're going to go about deciding when to complete the wells that you're deferring completions on? I think Clay spoke a bit to it. Obviously, price would be a part of it. But is there sort of a length of time that you have in mind right now? Or is there a price? Just maybe elaborate on your thought process there.

Yes. So I'll start that off. The hope would be that commodity prices and cash flow would improve and then we could move quickly to do those completions, whether that's sometime in the third quarter or the fourth quarter of the year. But that will all be driven by where cash flow is and what commodity prices are doing. With our own frac fleets and with the DUCs that these are creating, we will have the optionality to move very quickly and go forward with these completions. But right now, with current prices, it's a 10 to 15 completion reduction that will show up in the second half of the year.

And if that reduction stays in place, then they'll roll into 2024 obviously and be a part of that program.

So if I understood correctly, it's not just where the price goes, but Southwestern's overall free cash flow or your free cash flow position is another piece of the decision?

Yes. Let me pick one word up and move it out of the way. We have no intention of outspending our cash flow. So we'll moderate our activity in concert with all of the efficiency gains, the lower cost, the performance improvements and continue to optimize that program against the cash flow that we have available. From an economic perspective, these wells are economic and meet our criteria. It's really a focus on the discipline around capital allocation and investing within cash flow.

Got it. And then if I could just pick up the thread on service cost reductions. Clay, you already gave us some detail there with frac horsepower and OCTG. But I wonder if you could elaborate a little bit more from the perspective—or the differentiated perspective you have of also running service assets. What gives you the confidence that service costs will come in a bit?

Well, to begin with, we've updated contractual arrangements that are locking those improvements in where we utilized our openers at the end of the first quarter. We proactively went back to all our service providers as we saw the price reductions in January to solicit reductions. We've made good progress so far, which is helping with moving capital into the low end of guidance; not all of that capital reduction is coming from activity cuts—some is coming from inflation moderation also. Like many folks have talked about, OCTG is a big mover. We've seen reduced pressure pumping costs as part of the opener process and diesel is another component where those costs have come down. Our efforts will continue to stay strong in that space; we need to bring these costs down and get them more in line with the commodity price environment. We think there will be more opportunities to do so.

Our next question will come from Scott Hanold with RBC Capital Markets.

Yes. If I could just touch base on this adjusted plan to defer activity. If you step back and look at your 2023 overall budget, based on where strip is right now, would the intent be that you're still within your CapEx guidance and your production guidance albeit at the lower end? And second, if gas prices degrade a little more through the year, what would be the next actions?

Sure. Yes, a key point is that we're currently within the guidance range on capital and production. We're at the low end of that range on capital and just below the midpoint on production right now. If we see further commodity price reductions, then we will continue to be proactive in where we could take further adjustments. Hopefully some capital improvements could come from further inflation moderation gains, which wouldn't impact activity. But we've identified where the next round of activity cuts would come from: more dry gas reductions on the completion side in Southwest Appalachia, some dry gas drilling reductions in Northeast Appalachia, and in Haynesville, potentially a mix of both drilling and completion slowdowns if needed. So we have a plan. We're hopeful we can find reductions without cutting activity and that commodity prices will firm up.

That whole plan is optimized fairly continuously, with the output being capital required versus cash flow generated and making sure that we stay within cash flow with our investment.

Okay. It sounds like you guys have a lot of knobs and dials that you're working pretty aggressively here. My follow-up is on productive capacity. Bill, you've emphasized maintaining productive capacity. At a high level, do you think any of these actions so far reduce your productive capacity? And what's your sense of that level for Southwestern's assets right now—around 4.7 Bcf per day?

Yes. What you've heard is a well-balanced two-year plan that involves taking capital out in 2023, having that result in a modest reduction in production, but enabling us to move into 2024 and maintain a manageable ability to invest again within cash flow and arrest any decline. Taking a huge amount of capital and a huge production hit would make restarting the engine costly. We've optimized this. The benefit of inflation coming down, development plan optimization and the knobs you mentioned allow us to shape the program and minimize impact on productive capacity feeding into a higher gas price environment.

Okay, okay. So you feel pretty confident you've really minimized the restart costs and that's not an issue as we look into 2024 right now.

That's right. There are a number of proof points that back that up: inflation easing, efficiencies, etc. And our dual-basin position enables us to shift activity to liquids-producing inventory, which helps offset some of that as well.

Our next question will come from Doug Leggate with Bank of America.

Bill or Carl, I'm not sure which of you would like to take this, but I want to preface the question by talking about your well cost in the Haynesville. You've talked about driving down well costs and reducing drilling days, which were somewhat aspirational in the targets you laid out at the Analyst Day. It sounds like you're already achieving some of those. How much of the capital cost guidance you're talking about is permanent cost reductions through efficiency? And what would that mean for maintenance capital as you look forward into post-2023 activity levels?

Maybe I'll jump in. When we think about the inflation moderation we've seen, the Analyst Day set of annual capital had some further inflation assumed in the out-years. We don't see that now. Taking into account inflation moderation for full years and the ongoing efficiency gains that were not all baked in, there's about $150 million to $200 million of annual capital spend reduction in those out-years versus what we showed at Analyst Day.

Pretty much the answer I was looking for. Go ahead, Carl.

Yes. Maybe we translate that to the free cash flow guidance we gave over the next, call it, five years: well north of $1 billion.

Thanks, Carl. My second question: you have relatively small non-operated working interest in the Haynesville, maybe 3% or 4%. That probably gives you some insight into AFEs for the general industry, especially privates. What are your expectations for industry activity in the Haynesville? That's a big input to your focus on the macro.

I think the good news is we started the year with around 72 rigs in the Haynesville. Based on some Baker Hughes updates, that's dipped to 64—an 8-rig drop. We think over the full year there might be a 15 to 20 rig drop in the Haynesville. Some publications point to as high as a 20 to 30 rig drop. So we think it will continue, and it's consistent with our expectations that those drops are showing up now.

The public companies have pulled back too. At the end of the day, a lower rig count will lead to production leveling or declines depending on the operator. Privates were in growth mode; publics were more in maintenance mode, so results will vary by company.

Really helpful, guys. Before I jump, I just want to clarify: Carl, did you say we basically end up with more than $1 billion added back to free cash flow? Did I hear you right?

More than $1 billion. Price health, inflation and the compounding effects and the reductions in capital efficiency that Clay talked about.

Our next question will come from Arun Jayaram with JPMorgan.

I want to better understand the planned reductions in CapEx. The midpoint of your guidance range from last night is $2.35 billion; I think you're indicating you'll get down to $2.2 billion by deferring 10 to 15 completions. Can you confirm that and give a sense of actions you're taking today to take out about $150 million of capital? It sounds like moving one completion crew out of Haynesville and removing one additional crew from Appalachia earlier than previously planned—is that correct?

Yes, you have that right. We're down toward the low end of the original capital guidance range. It's not all activity reductions driving the capital down—approximately 40% of that reduction is coming from inflation moderation we've already realized. That's the basis for the $150 million. As for actions, we've already made notifications to service providers around those cuts and timing. Regarding the original guidance versus today, the May-ish reduction of a frac fleet in Haynesville that would have gone to year-end is over half a frac fleet when we average. And we cut another frac fleet earlier than originally planned, another roughly 0.7 of a frac fleet that's gone versus the February discussion.

Great. That's helpful. Bill, one for you: you left us a bit more on LNG, indicating there may be an LNG facility that comes on later this year—were you referring to Golden Pass, or can you provide more insights?

This is David Talley. We expect later this year a smaller, fast LNG project to go into service. We also expect Golden Pass and Plaquemines to potentially start commissioning. They won't actually be fully in service, but they will start commissioning and taking gas. So we expect those to ramp up possibly sooner than expected.

And can you give a sense of the magnitude of feed gas from those three projects?

That's hard to tell; it depends on the commissioning process. It's usually up and down and gradual over time.

The fast project will be about 400,000 MMBtu a day.

Our next question will come from Bertrand Donnes with Truist.

Following up on LNG: could you talk about your approach to future LNG agreements? The commentary gave the impression you're happy to indirectly benefit from LNG demand, but because you're well-positioned, are you better off letting others test the waters and then stepping in? Or are you waiting for something specific like a higher premium to Henry Hub or a lower deduct from JKM? Anything you're specifically looking for?

Our position gives us a good window into LNG markets, both domestically and internationally. We meet with utilities, liquefaction projects and buyers to understand the market deeper. We'll continue to evaluate contract terms and how far we want to go into liquefaction—whether to take liquefaction capacity or not. We think benefits from higher Henry Hub prices and potentially international LNG prices are present and we will position ourselves to take advantage of them. We'll evaluate arrangements on a risk-adjusted basis to ensure any agreement brings greater value than our status quo, which is Henry Hub-based projects. We're having dialogue with current projects and looking forward from where we are.

Okay. And looking at your hedge book, there's a notable drop-off in 2025. Is that intentional to coincide with LNG demand pick-up? Or is it because you don't want to hedge too far out due to market thinness?

Several parts to that answer. For 2025, our hedging practice is to hedge less the further out you go from a risk perspective. As a company, given our financial strength, we've moved to hedging at a lower level than in the past. It's important to get closer to the year you're trying to protect so you can better manage volatility. We generally triangulate toward hedging in the 40% to 60% range ratably, given our financial strength and ability to use collars and swaps. We actively manage the program once it's in place.

Okay. And one more: there's news about the Columbia Pipeline fire. Do you have a number on your exposure—were you able to change price points? Any color?

We are aware of the explosion. It moves about 2.2 Bcf a day from Appalachia down to the Gulf Coast. They have posted curtailments of about 400,000 total. We have a little over 300,000 of capacity on that pipeline, so we would expect a minor transportation capacity reduction. That won't impact our production. We can resupply our markets from other transport from Haynesville and move production around, so we don't expect to see an impact.

The strength of our portfolio and transportation options is clear. We have options beyond the nameplate on a particular pipe, and the team optimizes around that almost immediately when events happen.

Our next question will come from Umang Choudhary with Goldman Sachs.

I have a couple of housekeeping questions. Can you dig into your quarterly turn-in-line cadence and production cadence for the year if you don't pick up those deferred crews? Trying to understand the decline in production as you exit the year and as you start 2024.

Yes. This will result in a flatter quarterly production profile around that 4.6-ish Bcfe per day of net production versus the second-half increase that was in our original guidance.

Got you. And on working capital, Carl, you mentioned the working capital inflow in Q1 which you expect to reverse. I just want to confirm you expect the Q1 inflow to largely reverse over the next three quarters.

Umang, you got that correct. We enjoyed in the first quarter about $375 million of working capital inflow benefit. It's very typical seasonality in our business and how we manage capital. We do expect that to largely reverse throughout the year given the current strip.

Our next question will come from Jeoffrey Lambujon with TPH.

My first is on differentials, which came in better than expectations this quarter. Can you talk about what you attribute that to over Q1 and share a bit about your macro outlook for differentials for the balance of the year and key considerations?

Our Q1 differentials were stronger mostly because Northeast prices were higher than expected in Q1, primarily around our city-gate transports to the New York and New England markets. We also had some of our daily Northeast volumes sold at higher-priced locations during that winter volatility.

Great. As you think about the balance of the year, any guideposts or key considerations would be helpful.

We expect it to be within guidance.

And we hedge basis—always have—to protect that.

Great. As my follow-up, could you give a snapshot of D&C per foot in each basin for Q1, similar to the Q4 commentary last call, and how you think those might trend, particularly in Haynesville? How quickly can we see progress toward the low end of the range?

Certainly. Haynesville Q1 will be the highest well cost per foot because that's where we entered the new service cost environment at the start of the year. As inflation moderates and with efficiency gains, that will be an added benefit moving forward. In Appalachia, we were around $830 per foot in Q1; in Haynesville, we were right at $2,100 per foot in Q1. We're expecting Haynesville well costs to drive down every quarter as we move forward and approach the low end of our range in the back half and into the fourth quarter.

While the basins are different and have nuances, one proof point on the ability to get costs down is the work accomplished in Appalachia that we leverage across the dual-basin capability in every part of the business. Cost reduction is a big piece of that.

A reminder that Haynesville well performance benefits from greater depth and pressure in the Natchitoches fault zone, which drives some higher well costs in that acreage but is more than offset by the performance.

Our next question will come from Nicholas Pope with Seaport Research.

Could you talk about the balance in Appalachia between dry gas and liquids-rich portions? I think you've been steady at roughly two-thirds of activity toward the liquids-rich side. How much capacity do you have to process NGLs and oil from the liquids-rich side, and what's governing not swinging more toward liquids-rich?

We recognize the benefits of liquids pricing coming into the year and added nine more wells to sales in liquids-rich areas in 2023 versus 2022. The production impact showed up in Q1 with condensate and NGL volumes increasing. From an activity standpoint, overall activity is roughly 50-50 between Appalachia and Haynesville. We're balancing maintaining overall productive capacity as we move toward what we expect will be a better commodity price environment in 2024. We have flexibility to further adjust the mix if prices push us to do so, and we have the capacity needed to handle greater NGLs as part of that potential shift.

Our next question comes from Paul Diamond with Citi.

On the 10 to 15 completion reduction, is there any particular county or geographic area you're focusing on, or is that more of a game-time decision?

Most of it is in dry gas where the completion reductions are coming from. Of the 10 to 15, more is coming out of Haynesville tied to the reduction of the frac fleet we had modeled for the full year in mid-May.

Understood. And a quick question on flow assurance: you talked about delivering 65% to the Gulf Coast. Where do you feel the optimal long-term level is for that?

The 65% includes both our Haynesville position and transport from Appalachia, which is about 700,000 Mcf a day. If additional pipeline expansions come into play, we would look at participating from Appalachia, but there aren't any on the forefront right now. We would see growth coming from the Haynesville where we've announced participation in a few projects already.

There are many levers to pull and optimization choices across both basins that will determine that going forward.

Our next question will come from Subhasish Chandra with Benchmark.

Clay, can you describe cycle times for bringing DUCs back online—how instantaneous might that process be if prices are in the right zone?

In Appalachia, it will be quicker because we have two company-owned frac fleets in that area. We've moved rigs and frac fleets in the past—when we make the decision, in a week we're rigged up and drilling or pumping. We could move very quickly on completions of DUCs in Appalachia. In Haynesville, it wouldn't be as quick. With activity reductions anticipated there, we think late third quarter there will be opportunity to pick up third-party frac fleets to start earlier, or wait until 2024. That timing depends on availability and will be longer than Appalachia.

Would you say the variance is weeks in Marcellus and longer in Haynesville?

Yes, in Appalachia it will be weeks. For Haynesville, it's all about availability, so it will be longer.

Bill, any thoughts on A&D sentiment generally? We've seen headlines about Haynesville operators looking to tap the market. Does this put ice on it given the macro, or do some see the writing on the wall and put assets in play?

Our focus is capturing value from our scale in the two basins. Today's call shows results in that area. There are a number of things going on with other players, private operators in particular. The current extreme volatility makes transactions more difficult. We watch those dynamics closely; it depends on what's for sale and whether it can be accretive to existing portfolios, especially for gas assets.

Our next question will come from Noel Parks with Tuohy Brothers.

Could you discuss your thoughts on NGL pricing for the rest of the year into 2024? We're seeing divergence between products; what are your assumptions and key fundamentals?

On NGL macro, ethane is pressured by weak petrochemical demand or increased supply tied to natural gas. Ethylene margins and Asian exports can provide support. Whether economies go into recession will affect demand. For propane, domestic inventory is high after a mild winter; China reopening and plastics production in Asia can help exports and support prices. For butanes and natural gasoline, global demand for crude and related products matters—those are feedstocks to gasoline, so as gasoline demand rises, so does the value of those products.

Thanks. Given the timing—it's almost May—changes in activity levels and pads coming on that push later in the year have a fairly narrow window to impact 2023. So these decisions mostly affect 2024, right?

Yes. There is impact on full-year volume, but also on cash flow. We plan on a two-year rolling basis, so short-term adjustments help us invest within cash flow now and preserve productive capacity for 2024 when prices improve.

Our next question will come from Gregg Brody with Bank of America.

With respect to operating costs, if you reduce activity, do you expect to be at the higher end of guidance? Are you seeing similar disinflation on operating costs?

On LOE, we think we'll see some softening, but it's lagging capital inflation moderation because a big part of LOE is saltwater disposal and water hauling, where deflation hasn't shown materially yet. We've benefited from lower lease use costs on gas, which helps LOE, but LOE deflation is lagging capital deflation.

Gregg, we typically see LOE a little lighter in the first half of the year and then it ticks up a penny or two toward the back half. We expect that to be the case this year but still within guidance even with activity reductions.

Got it. I appreciate the capital discipline. Should we think you'll pay down more debt this year given the working capital outlook, or are you tapped out for now?

Simple answer: yes. Any free cash flow will go to debt repayment. We always look for ways to optimize our balance sheet, and any proceeds from the sale of noncore assets would likely go to pay down debt as well.

That concludes our question-and-answer session. I'd like to turn the conference back over to Bill Way for any closing remarks.

I want to thank you all for your interest and for your questions—great dialogue today. We look forward to sharing more of our capture of the tangible benefits of our scale with you next quarter. Have a great weekend. Thanks for joining.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines.