ANTERO Resources (AR) Q3 2026 earnings call transcript

It is now my pleasure to introduce Dan Katzenberg, Vice President of Investor Relations. Thank you. You may begin. Thank you for joining us for Intero's third quarter 2026 investor conference call. We'll spend a few minutes going through the financial and operating highlights and then we'll open it up for Q&A. I would also like to direct you to the homepage of our website at interoresources. com where we have provided a separate earnings call presentation that will be reviewed during today's call. Today's call may contain certain non-GAAP financial measures. Let's refer to our earnings press release for important disclosures regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President, Brendan Krueger, CFO, Dave Cantilago, Senior Vice President of Marketing and Transportation, and Justin Fowler, Senior Vice President of Natural Gas.

I will now turn the call over to Mike.

Thank you, Dan. Good morning, everyone. We're at a supply-demand inflection point for the natural gas market. LNG and power projects are expected to increase demand for natural gas by more than 40 BCF per day across the U. S. by 2030. including more than 15 BCF per day in our local Appalachian region. As we have seen through our marketing efforts and highlighted by the numerous transactions announced this year, demand for natural gas assets continues to increase.

The scarcity of core natural gas acreage is becoming apparent, which is resulting in higher and higher values placed on quality natural gas assets. and taro is well positioned to benefit from this inflection point supported by more than 20 years of cordial inventory our integration with entero midstream and being one of the few investment grade companies combined with our ongoing cost reduction initiatives we expect these advantages to drive peer-leading free cash flow per share growth over the coming years as depicted on slide number three Per a recent public analysis by Inveris, we have more than 1,400 core drilling locations remaining.

That gives Intero a multi-decade runway of premium inventory at a time when high-quality drilling locations are becoming increasingly scarce. As demand moves ahead of supply, we believe this inventory advantage will become increasingly valuable.

Now let's move to slide number four, which summarizes some of our quarterly highlights. Production increased 23% year over year to a company record of 4.2 BCFE per day. This was achieved while curtailing in excess of $100 million per day during the quarter.

Second, as a result of our cost reduction and margin enhancement initiative, we realized our lowest cash cost level in company history, 16% lower than a year ago period. Third, the diversity of our production and a lower cost structure led to our unhedged EBITDAX margin increasing 27% year over year, despite natural gas prices declining 4%. We used this strong financial performance to repurchase 1.6 million shares during the quarter and now have reduced our share count by more than 5 million shares since the beginning of 2025.

Turning to slide number five, I'll provide an update on our margin enhancement progress. Based on transactions we have executed on the date, we expect to achieve $140 million of our $300 million target by mid-2027. The overriding royalty interest transaction we entered into in 2020 met the return hurdles, resulting in 85% of the cash flow now reverting back to Intero on July 1, 2026, or $60 million of annual free cash flow uplift. We also executed on our firm transportation optimization strategy during the third quarter, resulting in $400 million per day of agreements and $20 million in annualized free cash flow.

During the fourth quarter, we are launching a formal process to expand on this strategy. Based on increasing demand pull interest that we are seeing, we expect approximately one BCF per day of firm transportation optimization agreements, resulting in an annualized free cash flow increase of $50 million.

Next, the VPP transaction will expire in the third quarter of 2027, resulting in an annualized increase in free cash flow of $30 million. Beyond mid-2027, increased dry gas development and the expiration of liquids from transport in 2028 puts us comfortably on track to hit our initial $300 million margin enhancement target.

In addition, during the quarter, we entered into attractive natural gas term sales deals with multiple parties at the Clarington market. In addition to these sales, since announcing Antero Midstream's Eastside Express pipeline last quarter, we have seen increased interest from multiple downstream counterparties seeking access to our natural gas at InterConnect on the pipeline. This project gives us widespread connectivity to numerous long-haul pipelines, providing exceptional optionality for contracting with end-user demand.

This project also reduces our all-in transport costs resulting in higher margins. I'll end with brief comments on the NGL macro.

The start of the fourth quarter has seen NGL prices increase 50% above the third quarter level. We expect NGL strength to continue in 2027, driven by robust global demand and low international inventories that require significant U. S. exports to return to sufficient levels.

Following a recent industry transaction, Antero is now the only producer with meaningful NGL exposure going forward. We remain unhatched on our NGLs providing considerable upside to our free cash flow. Now, to provide more detail on the current liquids and NGL fundamentals, I'm going to turn it over to our Senior Vice President of Marketing and Transportation, and Dave Canelongo for his comments.

Intero's liquids pricing increased throughout the third quarter following the Strait of Hormuz ceasefire ending in July and global liquids pricing rising steadily thereafter. The pricing momentum seen at the end of the third quarter has continued with Intero's C3 Plus spot liquids realizations now testing levels not seen since early 2022. The current geopolitical situation has had the greatest influence on the heavier end of the NGL barrel, particularly butanes and pentanes plus.

These products are critical components in gasoline blending and therefore are being bolstered by the current strength in gasoline prices as well as robust export demand for butane. As shown on slide number six, U. S. butane exports set all-time records in May this year at 893 barrels per day and remained elevated throughout the third quarter according to ship tracking data as international buyers scrambled to replace a steadily increasing number of lost Middle Eastern butane cargos. The price impact of these dynamics is seen on slide number seven.

The chart on the left shows the volume percentages of Antero C3 Plus NGL barrel. The chart on the right shows the revenue contribution by product and realized pricing in the third quarter. Despite Anteros propane volume making up 57% of the C3 Plus barrel, propane only contributed 43% of the revenue in the third quarter as butanes and pentanes plus prices were exceptionally high. However, the propane story has vastly improved since the third quarter. We have had a significant increase in propane pricing in recent weeks, as winter restocking and revised market beliefs of a more prolonged duration to the conflicts in the Middle East are requiring buyers to address the realities of the lost global supply heading into peak heating demand season.

On the export side, robust domestic demand for winter seasonal gasoline blending has tempered butane exports and immediately opened up more export capacity for propane at existing terminals. Second half 2026 propane exports are up nearly a quarter of a million barrels per day compared to the same period in 2025 according to ship tracking data, which is double the year-over-year increase seen in the first half of 2026 when there was intense competition with butane for dock space.

The impact of these trends on U. S. propane balances is already apparent and will likely be amplified throughout the coming winter withdrawal season. As shown on slide number eight, strong export demand in September and October has returned propane inventories to historical norms in the five-year range, in sharp contrast compared to the second quarter when stocks were well above the five-year range. As a result, the EIA has reported a withdrawal six of the last seven weeks, compared to just one withdrawal in 2025 over the same period. This signals that the start of the withdrawal season is happening much earlier than typical.

This is being reflected in pricing already as Montbellevue propane prices have rallied 34 cents per gallon since the start of October. Going forward, prices for both propane and butane will see tailwinds from new dock expansions coming online in the end of 2026 and into 2027. The increase in LPG export demand is well-timed, as VLGC ship deliveries in 2027 will be at an all-time high of 47, up from 38 expected deliveries in 2026, as illustrated on slide number 9. The de-bottlenecking of dock capacity from export expansions paired with new ship deliveries points to supportive forward netbacks and continued historical highs for propane and butane export volumes. The chart on slide 9 shows the VLDC ship order book is consistent and likely to set another ship delivery record in 2029 as we finish out this decade.

As mentioned in my remarks a moment ago, Intero's current spot C3 plus NGL prices are at the highest levels realized since 2022. Given the current geopolitical and supply side realities, the bullish trends impacting NGL prices are expected to continue and likely even escalate in the coming quarters. NGL propane prices are now trading just below record pricing levels seen back in March of 2026 at the start of the Operation Epic Fury conflict.

Stop premiums have tightened to single-digit levels. Mount Bellview prices have arisen as a result, consistent with Intero's predictions and prior earnings calls. Critically, Intero has far more exposure from increasing NGL prices than any other producer due to our high percentage of liquid production and completely unhedge portfolio.

With that, I will turn it over to our Senior Vice President of Natural Gas, Justin Fowler.

Thanks, Dave. I'll start on slide number 10 that illustrates the regional demand that is expected in our Appalachian Basin. On past quarterly calls, we have focused on projections for regional demand from power projects. This chart details this demand, which today is estimated at nearly 10 BCF per day, which includes approximately six BCF that is already in service or under construction and another four BCF that is waiting on FID. Now, in addition to this regional power demand, there has more recently been significant momentum on incremental demand pool pipelines, which we estimate could be over six BCF per day. What is noteworthy about these new pipelines is they're being underwritten by end user demand such as utilities and LNG facilities this compares to the past when producers had to take on these commitments to push volumes out of the basin this shift from producer push to the demand pull ultimately improves pricing netbacks and margins for antero unique to antero this demand provides significant competition for our natural gas volumes and firm transportation capacity as we As we enter the latter part of this decade, natural gas fundamentals continue to strengthen.

Incentivized by a sharp increase in international prices, LNG exports have recently hit record levels of over 21 BCF per day, with utilization rates near all-time highs. Higher international pricing and low storage levels are likely to ensure that the significant backlog of LNG projects which is projected to nearly double towards 40 BCF by the end of the decade come to fruition and Tara remains differentiated from its peers as the only producer with significant exposure to both this regional power demand and the LNG fairway through our firm transportation portfolio with that I will turn it over to Brennan Krueger, CFO of Antero Resources.

Thanks, Justin. In my comments today, I will focus on the financial benefits that we are already achieving from our margin enhancement strategy. Starting on slide 11, we look at a comparison in benchmark prices year over year. Despite natural gas prices declining 4% year over year, we were able to increase our unhedged EBITDAX margin by 27 cents per NCFE or 27% as we benefited from a lower cost structure and high liquids exposure.

Turning to slide 12, we increased production by 23% driven by the HG acquisition and several transactions that increased working interest in our gross production base. Notably, we were able to accomplish this net production growth without impacting the basin's gross production, which has remained essentially flat at 35 to 36 BCF a day during this period. Looking across our peer group, production was essentially flat year over year.

Second, we reduced our total cash costs 16% year over year, which compares to the natural gas peer group average, which saw costs increase 4%. And third, we produced the highest volume of NGLs as a percent of total production, which drives margin improvement during periods of lower natural gas prices. The 27% increase in unhedged EBITDAX margin occurred while our peer group saw EBITDAX margins essentially flat during that same period. This represents the true rate of change story at Antero. Importantly, this is just the early stages of reducing our cost structure and enhancing margins. We have a clear line of sight to significant further improvements over the next 24 months. Looking beyond 2028, we are already in significant discussions around firm sales agreements that will drive material margin improvement and anticipate that total margin improvement could double our $300 million target by early next decade.

Slide 13 compares free cash flow per share growth of the Appalachian Peer Group. We generated substantial free cash flow of over $1 billion over the last year, driven by a lower cost structure, high liquids exposure, and an attractive hedge book. We used this free cash flow to fund HG and other bolt-on transactions, reduce debt while also reducing our share count by more than 5 million shares.

This resulted in a 139% increase in our free cash flow per share year over year, compared to the peer group average that was approximately flat.

Looking ahead, we see the opportunity to nearly double our free cash flow per share driven by the execution of our margin enhancement strategy, organic production growth from a three-rig and two-completion-proof development plan, and meaningful share repurchases.

With that, I will now turn the call over to the operator for questions.

Yeah, the guidance is a 4.3 BCF with 15 to 20 BCF curtailments. All of those are related. When you have downstream issues in shoulder months in September and October, you'll have weak pricing. And we now have the flexibility with our local dry gas to shut in local dry gas when the prices are at, you know, $1.25 levels or below and still produce all of our liquids. our liquid is receiving over $60 a barrel.

We, of course, produce all of those, and then any local dry gas exposure we have, we shut that in. I'll also remind you all of that local dry gas is hedged at basis around the 90 cents level, so we are protected from that standpoint. But no reason to sell at those levels when a couple months later you can sell for $3 and $4.

Perfect. Thank you.

Yeah, well, there's a lot of thoughts on it. You know, Q4 will basically essentially double your free cash flow from Q3. And then when you look out, even with the backwardation in 27, you're above $3 billion of EBITDA with today's prices. So you have substantial increase in revenues. And that's even with a much lower backward-aided price in 27 and just looking at $60 for Q4. It's obviously clearly significant to us. Just to remind everyone on the call and yourself, we produce 45 million barrels of C3 plus annually. If you're talking $20 incremental increase from this past quarter, that's $900 million of incremental free cash flow.

Or $225 million according. Big numbers.

Yeah.

Yeah, and differentials, obviously third quarter is always the weakest, you know, in the industry. You've always got September and October is kind of your widest differential. and now that we have local dry gas you'll see you know a little weakness there a little more pronounced in q3 uh just because of some downstream outages and that's why we're at that 30 cent level you know you look at q4 you're maybe in the 20 cent range so you get a little bit of improvement and when you look at 27 you're maybe a flat to dime back also remember a lot of that's our firm transportation optimization. So we're able to get others to pay us a bit of a premium at the index, but have more index exposure and not have the transport expense.

So there is a benefit on our cash costs that's more than offsetting those differentials.

Yeah, I think that's a fair assessment. So if you look at those transactions, a little over $250 million a day. You know, we have about $400 million a day today going to the Clarington market. So you'd probably expect to see us do a bit more of those transactions over time. that Clarington market is in the, you know, 20 to 25 cents above M2 if you can do longer term deals. If you're selling, you know, on the month or on the day, it's probably closer to like an M2 plus 10, plus 15. So it does add some nice margin to the business when you can lock it out longer term.

And then I just say overall, I think we see very strong demand at that Clarington market, A lot of demand pull coming from that market, and so I'd expect us to move more volumes up to that market over time, just given the demand pull and the inbounds we continue to get as it relates to that demand pull at that market.

Yeah, we're trying, you know, one of those is obviously just the expiration of our liquids transport. I believe it's 100 million of the 160 remaining. The other 60 is more dry gas developing in these deals that Brendan's touched on. Local getting the premium pricing on that as other transport rolls off. So that's the other 60 million, but 100 million is just the expiration of those liquids contracts. You can see that in our commitment table.

Yeah, trends down over that time. Just to remind, on Q4, it's just a tad up only because of fuel expense, a little higher commodity prices, nothing on the base business. The base business is kind of flat at that 205 level currently, but that goes lower as we continue to execute on these firm transport optimization agreements and also as we kind of book continued natural gas sales agreements locally with firm transport rolling off. that continues to trend out and definitely trends down in 27.

No, that basically goes east-west across our dry gas acreage that one of the last few tier one dry gas undeveloped acreage, the 100,000 acres that we have on the east side, building that all the way across basically to connect with our Sherwood kind of transport into that area so you have the optionality to flow it on multiple different pipelines.

I think we have seven or eight interconnects. We're getting so much interest on that. I don't know which way it's going to go or which pipes it's going to go, but that's what it does. It connects that 100,000 acres and allows for that dry gas development to find the best price. That will be a little bit, I think, of maybe some dry gas growth, but really kind of replacing liquid production as well. So we don't forecast much gross gas, but just more of kind of a portfolio approach around our production mix going forward.

No, my initial remarks is here. We have one pad called the Barnard pad that was a duck. We were going to wait to see where prices were to complete it. It's a 1300 BTU pad. We're completing it right now on the western side of our field. Obviously, with C3 plus prices, $60 plus, we're completing that right now.

Now, think about it the same way with this year. I mean, our goal is to be the most capital efficient operator in the basin, and we kind of proved that out over the past couple of years that we are. And that's keeping a consistent program of three rigs and two completion crews, and that's what our intention will be. We will always have a discretionary component to whether we complete a couple paths in the Q4 just depending on commodity prices because we're not going to complete into known weak commodity prices in the winter or known weak liquids prices.

You saw kind of that strategy play out this year. We were patient and disciplined, and then we looked in September. We decided, well, let's just hedge our lean gas at $3.50. You saw those hedges we added during the quarter, basically $100 million plus. They have hedges at $350 for $27 and $28, so to protect those economics. And then, of course, complete the liquids pad with $60 plus NGLs. So I think you're going to expect a similar capital plan next year as we had this year.

Yeah, I think it depends on which firm sales and which markets you're talking about. So in the Clarington market, and when we have FT rolling off as well. So in the Clarington market, a lot of times you can roll these one to two years and get those premiums. I think over time, you'll likely see those contracts extend.

And then I think Mike talked about the east side lateral earlier as well. I think the benefit there is when we have FT rolling off, and I'll call out one in particular. I mean, we've got a contract that's about $200 million a day that we're having many discussions on just replacing that selling volume off of Eastside Express.

And if you replace this $200 million a day contract with volume at an M2 plus contract off of that pipe, it's upwards of $75 to $80 million of margin enhancement. That's just one $200 a day contract. So that gives you some magnitude of the margin enhancement we've talked about. We've got the $300 million by year-end 28, and then we talked about doubling that beyond 2028. Well, that doubling is really related to selling some of these longer-term deals in Basin, both at the Clarington Market but also off of Eastside Express. And there may be additional pipes down the road that will sell off of AM-built pipes as well that we see significant margin pick up on.

Yes, it gets to both. The $400 is inclusive in that one BCF, so it's a total of one BCF. And then the $50 million is net of the realization impact.

It's the average of 26, high single-digit growth over the average 26.

Sure.

Yeah, we're not trading it away. We're optimizing it. So it's not really market dependent. It's just wherever, you know, there's some demand pull that has going to pay us premiums. And we'll go out with much more than the BCF. The BCF is just our target. And then we'll see where we get the best response and best margin improvement.

That's correct.

Yeah, so I think I mentioned we've got 400 a day flowing there today. I think given the demand poll we're seeing at that market, you know, of that 16 BCF a day, you have, you know, at least I'd call it five to six BCF a day being pulled out of that market. And so taking that 400 up another BCF a day is not unrealistic in terms of going additional volume at that Clarington market, just, again, given the demand poll that we're seeing there and the inbounds we're getting as it relates to folks needing supply.

Yeah, I mean, I think we still expect that pipeline to remain an ethane service. I mean, it's possible you could see another product move on it, and that's certainly out there as an idea. But we still think a number of folks in the basin will rely on that pipe for ethane transportation, so don't really see that as something that we're going to spend a lot of time or attention on. Just overall, the base and realizations, our entire strategy has been around margin enhancements. You're going to see us optimize our portfolio as things expire at the end of 2028.

Realizations may come down, but overall costs will come down more than that. I think that's directionally what you'll see from us moving into the late part of the decade.

Yeah, I think for 2027, market expectation is things will stay pretty elevated, at least through the first half of the year. But as we move through Cal 27, you'll start to see some relief there as well. I think the big question is, is there actually enough U. S. supply to fill all of these dock expansions on day one. I think the answer to that is probably no, not right away. And so I think that'll also maybe create some new perceptions in the freight market that may not be there right now that'll also help temper freight rates.

Exactly. On that last point, it's still an advantaged structure. You saw that play out in 26. You saw it's been having M&A from both an upstream and midstream perspective and being able to value the midstream appropriately and the upstream appropriately really helped us on our large acquisition this year. In addition, AM is now positioned for the first time in quite some time to have these regional growth projects, and that will benefit from the lower cost of capital as well.

And one thing you need to do in Appalachia is you need to control the midstream, and we control it. So strategically, there is no difference. We control the midstream on our development, on our acres, and we'll always control the midstream. So having the lower cost of capital is a benefit.

Thanks.

Yeah, Dave, I'll take that one, Subhash. I mean, I think, you know, oil pricing around $100 WTI, you know, I'll call 100 mid-teens per rent. The prices that we're seeing right now for propane and butane in the international market, you know, delivered, are very much in line with historical levels, like what you would see relative to math and oil prices in those markets. So, you know, I think your question is a good one around how much this is, you know, more related to a bit. Well, certainly, yes, it's had an impact, obviously, on liquid prices, refined products, availability, et cetera.

I think the thing that we've seen, it's been a little bit different. You've seen more, greater recovery in oil through the Strait of Hormuz, and you have an LPG. I mean, kind of looking globally, we're still down about 25% of waterborne LPG, you know, due to the impacts in the Strait of Hormuz, just not as much of a recovery on the LPG side in that region. So, you know, that probably lends itself to, you know, additional tailwinds kind of relative to oil for the NGL barrel, you know, moving forward if this continues to, you know, prolong itself.

But certainly, you know, $100 oil is going to lead to a pretty strong NGL price, and that's what you're seeing in our realizations in the fourth quarter.

No, it's generally, you know, like we talked about, we want balance. It's more like 50-50, kind of on a go-forward basis between the dry gas and liquids. That's not on production. That's actually on development pads. It really doesn't move the needle. you still save 70%, you know, kind of liquids and 30% liquids and 70% gas.

Yeah, I think it would be a little, you know, a 4.5 kind of a risk curtailment kind of number. You know, if you had not unrisking and no curtailments thought about or just put in a range, I think you'd be above the four-pots. And I think on a year-over-year basis, if you go Q4 to Q4, you'll certainly see some growth.

Exactly. And, you know, the same thing on the production on the duck capital. We'll always have kind of a duck component. So for the Q4, not that it will influence 27, but it will have a little bit of influence. And when we turn in line pads and maybe waiting until December months to turn it on instead of like a September, October in a year can influence the production as well.

Not really. We were looking at that yesterday, just trying to get our arms around it. We're really not seeing anything on the service. You see maybe 1% on raw materials, on like oil-based mud, or a little bit on steel, but nothing material, nothing you would really note if you weren't trying to dive in and analyze it.

Yeah, I think September and October we saw the lowest regional gas price we've ever seen. So that wasn't anticipated. There was like a couple of weekends where it was like 60 cents, 60 cents. We didn't sell enough, of course, but the weakness was exacerbated by all the downstream issues that occurred in September and October. So it backed it up on a historic level back up into the region. So we, of course, didn't forecast that. We don't forecast it going forward, but we're obviously flexible enough to not have to sell into that so we are we have the ability to just wait and sell it in December so that's kind of what went against us that and we've been way more successful in our optimization of the firm transport than we thought the demand pull is real and you saw that in the third quarter and so when that occurs you have slightly lower realized price but much lower cash production expense okay appreciate it Thank you.

Yeah, I think you'll see that play out more ratable over time in 27 and 28 as we continue to sign some of these sales agreements and pick up margin, incremental margin on each of those agreements. You'll see that $55 million achieved. So ratable throughout the next couple of years is a good way to think about it.

Yeah, I mean, the easy way to think about it is, you know, you have some portions of our FT portfolio. When you look at the all-in netback and all-in cost, demand variable, all that it takes to get to certain delivery points that are upwards of, you know, $1.35, $1.40 back of Henry Hub. Well, if you look out at the local price, you know, you're $0.65 to $0.70 back of Henry. and a lot of these agreements that we're looking at with counterparties that need the supply, they're willing to pay a premium on top of that. So if you can replace volume, significant volume that's $1.35 back of Henry with stuff that's called 55 to 60 cents back of Henry in basin, that's the big driver of that doubling of margin that we see.

So we're not even assuming we're going to keep the good FT that goes to the strong LNG pull, but the FT, we're going to optimize the FT when it's rolling off and replace that with longer term sales agreements in basin. We're seeing a lot of, like I said, a lot of interest on those deals so feel very confident about that ability to be able to double that $300 million target.

We're a buyer of acreage and being one of the few investment grade companies with scale already we have an advantage plus we have upstream and midstream and we control a lot of the transport and all the infrastructure and we are the builder, industrial builder of Northern West Virginia so we are the consolidator of West Virginia acreage. So that gives us an advantage. It is scarce, but we do surround a lot of the acres now, so we're probably the only buyer of a lot of this, our only logical buyer. And there's a lot of efficiencies and synergies that we can value, so that makes us a likely consolidator of the West Virginia area.

Yeah, we're opportunistic depending on where the market's at. Generally, when we have buybacks, a lot of times it's on like 10B51 plans, and we set in motion a buyback at a share price relative to propane, natural gas price, or, you know, it's kind of a two- or three-factor equation. So we assess that every quarter. We look at where we're at versus kind of where the commodities are at, where our free cash flow is at, where our debt's at, where our M&A opportunities are at, and set it then. So, you know, we're highly opportunistic. we're very this year we're happy that we were able to buy in over the last five quarters, five million shares. We hope to continue to do that.

At these levels the opportunity seems to be there.

Yeah, well, we brought the way that we operate to their assets the way we've done it for the last 15 years. You know, we have over 1,500 wells of experience, and we brought our operations team, which is the best in the business, to do it. You know, one easy one to look at is HG was, you know, doing three or four stages per day of completions. We do 13 to 14.

So that's always going to lend itself a lot of efficiencies. The drilling days, too, were sub-five days per 10,000 feet. They were double digits on that metric. So just those two, it's a lot of just bringing our best practices to those assets, and we've done that. So that's how we've been able to achieve those. Those have been ahead of schedule.

The synergies, I think we said $75 million. You know, we're well in the triple digit in that, over $100 million for the year on that, and those will continue going forward.

Well, it's probably to see. The benefit that we have is, I think in one of the calls, we have 30 paths. I think I said it's exactly 28 paths. So we know exactly which ones are margin enhancing and which ones are not. That knowledge is invaluable as we go forward. And so we'll be able to pick the best ones, capture the highest margins, and then the ones that may not be as margin-enhancing, replace those with those local firm sales or local natural gas sales agreements. So we're in a great position.

Sure.

So we already captured it through all the transport we have. Others don't have the transport, so they're trying to generate that without actually physically having the ability to flow their equity volumes. So we've captured it through the transport, and then we're going to capture the real margin by floating on that to the best pass to the coast and get the R between the international pricing and the U. S. pricing. So that's how we've chosen to capture it. stay floating, get to the coast, actually have our physical volumes that are being transported.

And then that way we can continue to reduce our commitments but still enhancing our margins.

Yeah, significant economic enhancements. I think next year our drilling is going to average 18,000 feet, which is a record. I think this year it's made 15 to 16. We completed it to 25. You get a lot of cost per foot advantages by going out that much longer. We continue to push it. I think in the coming years you'll probably see us maybe next year and the next go over 30,000. That's the goal, so we'll continue to push and push. And, you know, the beauty of HD and now our Eastside Express, the development of that 100,000 of undeveloped natural gas acres is we can perfectly plan it. And I think you touched on the number. You know, you get five wells going north 20,000 feet, five going south 20,000 feet.

And that seems to be the perfect plan with one high-pressure pipe going through the middle of a row of hundreds and hundreds of locations. So that's where we're headed and to optimize that, and I think you'll see that in the coming years.

Sure.

I'd like to thank everybody for joining us on the conference call today. If you have any more questions, please feel free to reach out. Have a good day.