ANTERO RESOURCES Corp Q4 FY2023 Earnings Call

Hello, and welcome to the Antero Resources Fourth Quarter 2023 Earnings Conference Call and Webcast. A question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It's now my pleasure to turn the call over to Brendan Krueger, Vice President of Finance. Please go ahead, Brendan.

Thank you. Good morning, everyone. Thank you for joining us for Antero's fourth quarter 2023 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 www.anteroresources.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. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman, CEO and President; Michael Kennedy, CFO; Dave Cannelongo, Senior Vice President of Liquids Marketing and Transportation; and Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Paul.

Thanks, Brendan. Good morning, everyone. I'll start my comments on Slide number 3 of our presentation, titled Drilling and Completion Efficiencies. 2023 was a transformational year for Antero as our operating performance made significant advances. Our drilling and completions teams set a number of company and industry records throughout the year. As an example, days per 10,000 feet of lateral drilled averaged 5.5 days in 2023, a decline of 14% since 2019. On the completion side, 2023 completion stages per day averaged nearly 11 stages a day, a 35% improvement compared to the 2022 average and more than an 80% increase from 2019 levels. The result of these operational improvements was significantly shorter cycle times, as shown on the bottom of the page. These cycle times reflect the total number of days it takes on average from first spudding a pad to turning that entire pad to sales. Since 2019, our cycle times have decreased by an impressive 65% and averaged just 160 days in 2023. Shorter cycle times mean higher capital efficiency, of course. In addition, our well performance continues to improve. This operating momentum is highlighted by the fact that while targeting a maintenance capital program this last year, our volumes actually grew 6% in 2023 compared to 2022. Most importantly, these capital efficiencies and well productivity gains drive a reduced maintenance capital budget. Now let's turn to Slide number 4 titled, Efficiencies Translate to Lower Maintenance Capital in 2024. In 2024, we expect production to be flat, averaging between 3.3 and 3.4 Bcf equivalent a day. Meanwhile, our drilling and completion capital is expected to be down over 25% compared to the prior year. Our maintenance capital budget midpoint of $675 million is over $225 million below the $909 million that we spent in 2023. The operating efficiency gains captured in 2023 allowed us to drop one drilling rig at the end of last year and then to drop a completion crew at the beginning of this year. We now plan to average two drilling rigs and just over one completion crew for our maintenance capital program in 2024. Also contributing to our reduced capital budget is a lower base decline rate. As we enter year four of our maintenance capital program, our decline rate is substantially lower in the mid- to low 20% range. This low decline rate requires less capital to hold production flat. In addition, our land capital budget midpoint of $88 million is down over $60 million compared to 2023. In total, this will result in $275 million to $300 million of reduced capital spending compared to last year while maintaining the same production level. This significant reduction in capital highlights the high-quality asset base at Antero and the flexibility that we have. As we look ahead to 2024, these significant capital savings, combined with the recent increase in NGL prices, is expected to generate free cash flow during the year. This positive free cash flow generation is expected to occur despite being unhedged in today's challenging natural gas price environment. This positive free cash flow outlook is even more impressive when considering that the current strip is at the lowest natural gas price for any calendar year outside of the COVID year in the last 25 years. Now, to touch on the current liquids and NGL fundamentals, I'm going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Cannelongo for his comments.

Thanks, Paul. The macro picture for NGLs has improved materially this winter due to a combination of strong domestic demand and consistently high export levels despite the challenges seen in the global waterborne shipping environment. Focusing on propane, as a result of the strong exports and winter weather, inventories have declined by 45 million barrels since October. In just a few months, propane stocks have moved from the high end of the five-year range to five-year average levels, as shown on Slide number 5. This return of propane inventories to the historical average has tightened the market and driven bullish sentiment with C3+ NGL prices as a percent of WTI increasing from 43% last fall to 57% today, driven largely by propane prices rising to above $0.90 a gallon. Slide number 6 illustrates the strengthening relationship we've seen between WTI and C3+ NGLs in recent months as Antero's NGL price has increased from $38 per barrel on average during 2023 to over $43 per barrel currently. In addition to the strong domestic fundamentals, propane exports have continued to impress. Last year was a record year for propane exports, which averaged 1.62 million barrels per day for the full year 2023, as shown on Slide number 7. 2024 has also started off strong with exports averaging 1.72 million barrels per day year-to-date, an increase of nearly 200,000 barrels per day above the same weeks last year. These strong exports are occurring despite major volatility in global shipping routes, including restrictions on passage through the Panama Canal and rising geopolitical risks in the Middle East affecting passages through the Suez Canal and Red Sea. The Baltic LPG rate, which is a metric of the shipping cost of liquefied petroleum gas on a VLGC or very large gas carrier, increased to record levels at the end of 2023, primarily due to limitations on Panama Canal transits that resulted in shipping capacity being tied up in longer routes around the Cape of Good Hope as shown on the graph on the right of Slide number 8. However, this trend has reversed recently as the effects of the Panama Canal restrictions on LPG carriers have eased with Canal passages increasing in January, as a result of the global shipping reshuffling. Additionally, last year was a banner year for VLGC new build deliveries with 41 deliveries in 2023, as seen on the graph on the left of Slide number 8, which is more than double the typical yearly delivery. VLGC supply is expected to continue to grow in 2024 with 21 more ships being delivered. These deliveries are occurring at the right time in the market with U.S. LPG export growth and the current challenges facing global shipping that have increased transit times in altered routes. As a reminder, Antero exports over 50% of our C3+ production, skewed heavily towards propane and butane directly out of the Marcus Hook terminal in Pennsylvania and has the ability to price our barrels on international indices. Antero will benefit from the current lower shipping rates by being able to capture more of the spread between domestic and international pricing for propane and butane. Also, Antero's export volumes are not impacted by potential constraints at the Gulf Coast export docks, which are at high utilization rates with current export levels and limited capacity expansions expected until 2025. I'll conclude my remarks this morning acknowledging that with these fundamentals I have just discussed, 2024 is poised to be yet another year in which our exposure to NGL pricing will be a supportive differentiator when compared to other natural gas producers. With that, I'll turn it over to our Senior Vice President of Natural Gas Marketing, Justin Fowler to discuss the natural gas market.

Thanks, Dave. I will start on Slide number 9 titled, Growing Global LNG Market. This is a slide that we have shown in the past but is updated to reflect the potential impacts from the recent pause on LNG facility approvals from the U.S. government. Regardless of the duration of this pause, we expect very little impact on LNG demand growth into the end of this decade. In fact, only three LNG facilities in our stack chart could be impacted. You see those highlighted by the red boxes. The remaining projects still result in over 10 Bcf of incremental demand by the end of 2027. This would bring the current U.S. LNG export capacity of 14.5 Bcf per day to nearly 25 Bcf per day during that time. This is a substantial demand increase that we expect to tie U.S. natural gas prices more closely to the higher international prices. Antero is uniquely positioned to benefit from these higher expected U.S. natural gas prices, particularly prices linked to LNG demand growth near Henry Hub. Next, let's turn to Slide number 10 titled, Not All Transport to the U.S. Gulf Coast is Equal. As a reminder, we sell substantially all of our natural gas out of basin, including approximately 75% to the LNG corridor. Our firm transportation portfolio provides us with direct exposure to growing LNG demand along the Gulf Coast and importantly, into Tier 1 pricing points along the LNG corridor. This slide illustrates the significant benefit in selling our gas at Tier 1 Gulf Coast pricing. Based on the current strip, Tier 1 prices reflect increasing premiums to NYMEX in 2025 and beyond, including the TGP 500 Index, which represents 30% of the 2.0 Bcf per day of Antero directed Gulf firm transportation, where premiums have increased to $0.29 above NYMEX in 2026. Antero also delivers to ANR Southeast and Columbia Gulf Onshore points, which represents an additional 60% of premium delivery that over time will also appreciate with the current LNG export buildout. Meanwhile, there are a number of peers that sell their gas in Tier 3, which is currently trading almost $0.25 back of NYMEX in both 2025 and 2026. Further, we think Tier 3 pricing could continue to widen as LNG facilities are placed in service and Tier 1 pricing pushes higher. Yellow stars on the map highlight Antero sales points, which were strategically negotiated to bring our volumes directly to the LNG doorstep. As depicted in the pie chart on the top left-hand side of the slide, Antero sells 90% of its gas at Tier 1 pricing. This compares to the average of our peers, which sell 67% of their Gulf directed volumes in Tier 2 and Tier 3 pricing. Looking ahead over the next two years as LNG export capacity increases by nearly 6 Bcf, we expect Antero sales points to be priced even higher than NYMEX at these LNG facilities as they compete for supply. The premium received at these sales points could also see further upside due to the delays on certain downstream pipelines that had previously been expected in the Haynesville by the end of this year. Delays into 2025 or 2026 would make our already existing firm transportation that much more valuable in the growing LNG market. Lastly, I would like to touch on power burn demand trends. Slide number 11 titled, Power Burn Demand Continues to Outperform. This slide illustrates color burn demand over the last 10 years. Continued coal to natural gas switching, along with higher electrification demand for everything from electric vehicles to high-powered AI data centers leads to increasing natural gas power generation demand. Despite the majority of forecasts that you see, which project flat or even lower power burn demand, power burn demand in 2024 is once again outperforming expectations. We believe there has been a structural shift toward reliable, clean and affordable natural gas that will continue to increase power burn demand annually going forward. This demand growth, combined with rising LNG and Mexico exports creates a significantly higher base demand level than we have ever experienced in the past. While there are certainly near-term storage challenges, we expect these fundamentals will provide support to natural gas prices and lead to periods of higher prices in the coming years. With that, I will turn it over to Mike Kennedy, Antero's CFO.

Thanks, Justin. First, I'd like to discuss our multi-decade inventory position. Turning to Slide number 12 titled AR Has the Largest Low Cost Inventory. This chart compares inventory positions across our natural gas peer group based on data from a third-party report. Antero has the most sub $2.75 per Mcfe drilling inventory at 22 years. It is important to note that this inventory comparison is after our peers have spent a combined $30 billion on acquisitions over the past three years. In contrast, through our organic leasing efforts, we have invested $340 million over that time to acquire targeted drilling locations within our development footprint. On average, we have been able to add locations for less than $1 million per location through this program. This is less than half of the nearly $2 million average cost per location for the peer acquisitions. In 2023, Antero organically added over 100 premium core locations at an average cost per location of less than $1 million, more than offsetting its 2023 drilling program. Next, I'd like to go a little deeper on the capital efficiency improvements that Paul touched on in his comments. The chart on Slide number 13 compares capital efficiency of the natural gas peer group or the amount of capital required to achieve production targets. Antero has the lowest capital per Mcfe of its peer group at just $0.55 per Mcfe. This is 40% below the peer average of $0.92 per Mcfe. This capital efficiency measure is important when comparing asset quality and operating capabilities of each company. The scatter plot on Slide number 14 really magnifies the peer-leading capital efficiency at Antero. This chart shows the year-over-year change in production on the y-axis and the year-over-year change in drilling and completion capital on the x-axis for the natural gas peers. These estimates are based on company guidance for those that have announced 2024 guidance and consensus estimates for those that have not. When you compare the production targets for the drilling and completion capital invested to deliver that production, we are by far and away the most capital-efficient operator in Appalachia. Let's turn to Slide number 15 titled Free Cash Flow Breakeven, which summarizes the benefits of our combined capital efficiency gains and high NGL exposure. Beginning at the top left-hand side of the slide, our total capital budget, drilling and completion plus land capital is expected to be down nearly $300 million in 2024 compared to last year. Moving down to the bottom left-hand side of the slide, the 2024 NGL strip is more than $3 per barrel higher than in 2023. As a rule of thumb, every dollar change in NGL prices results in a $40 million change in cash flow. Thus, higher NGL prices in 2024 drive a $135 million increase in cash flow. In combination, the result is approximately $430 million of incremental cash flow in 2024 compared to 2023 from our capital efficiencies and NGL focus, which more than offsets the weakness in the natural gas market, even while being unhedged. Turning to Slide number 16. This slide compares free cash flow breakeven levels. Our low maintenance capital requirements and high exposure to liquids results in the lowest unhedged free cash flow breakeven price among our natural gas peers. As we look ahead, we believe Antero is best positioned to create significant shareholder value. We have product diversity as the largest NGL producer and exporter of LPG, the highest exposure of natural gas production to the LNG demand center and the lowest amount of hedge volumes, which creates substantial leverage to rising Henry Hub prices. In addition, our realized prices have basis upside due to our premium sales points along the LNG fairway. Finally, we are the most capital-efficient natural gas producer in the U.S. with the lowest free cash flow breakevens. The combination of downside protection from our liquids production, a strong balance sheet, and the lowest breakeven price combined with the upside exposure through our takeaway to the LNG demand center, places Antero in a significant competitive advantage as we move towards the substantial increase in demand expected from near-term LNG projects. With that, I will now turn the call over to the operator for questions.

Our first question today is from Arun Jayaram from JPMorgan Chase & Co. Your line is now open.

My first question is related to LPG pricing, perhaps for Dave. Dave, I'm looking at your weekly pricing update that you provided on Monday and it shows kind of your mix between Mont Belvieu and global pricing being about a 50-50 mix. Given strength in the international market, do you have any flexibility to increase, call it, your leverage, just given the strong export trends? And if so, can you maybe quantify what that could mean for your realizations?

Yes. So, when we talk about that exposure, it's really on the overall C3+ barrel. I think we've talked about in prior calls. There's times even in the summer where we're exporting 85%, 90% of our propane, so we do utilize that flexibility that we have with our marketing plan to do that. But no, I mean other than that, the isobutane, the pentanes, we're not exporting those products. So that's always going to stay in the domestic pool, which is why you're going to see that 50-50 relationship that you're talking about.

And then just looking at the last pricing update, there was about a $0.04 to $0.05 per gallon delta between propane between international and Mont Belvieu. How much of the international realizations are impacted by net shipping costs? And as those net shipping costs as you show normalize, what kind of uplift could that provide?

Yes. So quite a bit. I mean we've seen that this year recently. You've seen the Baltic rates collapse pretty dramatically. And so we benefited from that. I think you've seen propane today this morning trading gallons at $0.94 a gallon. So a lot of that has been driven by the fact that the freight costs have decreased. If you look at destination pricing in Asia, you're not seeing propane price at strong levels this winter relative to naphtha, it's actually similar pricing to what we would see in the summertime. So the run-up in Mont Belvieu pricing has been really driven by the collapsing freight rates that have allowed Belvieu to rise. The other piece, I think, that we see with our portfolio is the Gulf Coast stocks, as we've talked about, are very highly utilized. So as you move into the spring and summer season, domestic demand wanes. We think you'll see more pressure to try and export out of those facilities. And until they expand in 2025, that will be limited. So that value premium that you get at the dock will rise and our ability to access that directly with our firm capacity out of Marcus Hook will allow us to take advantage of that more as well. So, kind of two things working in our favor, the ability to get to the waterborne price, not just somewhat landlocked at Mont Belvieu as other producers are and then the improved freight dynamics have allowed us to benefit more than others.

I have a quick question for Justin. If the momentum pipeline is delayed due to some timing issues, what impact do you anticipate on Tier 1 pricing in the Louisiana LNG corridor?

Once we start seeing the Plaquemines facility introduce gas sometime later this year, we would expect to see that forward basis continue to increase, keeping an eye on ANR Southeast basis. Right now, it's showing a positive first Henry, and it can range anywhere from $0.07 to $0.09 over at the moment. Any of those delays that are going to bring less gas down to that Henry Hub region, we would just expect to see that basis continue to increase as more competition enters into the market with Golden Pass and Plaquemines coming on.

Our next question today is coming from Bertrand Donnes from Truist Securities. Your line is now live.

On Slide 12, you outlined your low-cost inventory. And I'd say a while ago, 15 years of inventory was enough, maybe it moved to 10 at one point. But when you're sitting at 22 years, you could split the company in half and still not be in the running out of inventory group. So the natural question would be, is there some interest in maybe divesting some of the inventory that's at the end of the stack? And then just a broader question is, can you really get two parties to come to the table in this current gas price contango? Or does one party just simply refuse to look to the outer years?

Well, the first one, no, we are a consolidator of the liquids fairway of West Virginia in that 22 years. About half of it is liquids. The other half is our dry gas option, which is on the eastern side of our field. So that provides a good dry gas option, it allows us flexibility to toggle between liquids and dry gas. Liquids is obviously very accretive today. I think we get over $1.10 uplift from the liquids compared to the Henry Hub price. So we've been focused on that. So we want to continue to consolidate that. And with our scale and the liquids midstream we own and the transport, the barriers to entry are very high. So no one really could develop that outside of having those attributes. So we continue to consolidate and look to own more and more of the inventory. And on your second question, I really didn't quite understand that. On the contango of natural gas, we're really more looking at the liquids prices driving the economics.

Yes. I was just wondering, in any negotiations you're doing maybe even on the acquiring side, are both parties able to kind of agree on the higher gas price in the future? Or does the buyer always say, I see only the near-term lower price, and I won't give you value for the outer years?

Yes. We really haven't been in any discussions. We're focused on our organic leasing. That's where we add the most value, as I mentioned, less than $1 million per location in M&A, so over $2 million per location. So we're not really in those types of negotiations. When you're doing the brick-by-brick, ground game of organic leasing, you're just dealing with leaseholders that enjoy that you develop their minerals.

Makes sense. And then the second question is just some of your peers are earmarking a significant amount of capital for infrastructure build-out over the next few years. And I would assume this lower full year '24 guidance doesn't have that much included into it. So could you maybe talk about how you're able to operate efficiently without that kind of overhead that your peers have?

Yes. With Antero Midstream, we own 30% of Antero Midstream. Antero Midstream has built out the largest liquid system in Appalachia and we have all the processing and high-pressure and low-pressure and then the firm transport connects to that. So we've already made all those investments Antero Midstream has and they are on 30%. But Antero Midstream came out with their capital and their capital is much lower as well because it's just in time really building that last mile of low pressure in water. So we've already made all those midstream investments. It's one of the reasons we're the unconstrained E&P. We don't have midstream constraints, and everything is already in the ground.

Next question is coming from Jacob Roberts from Tudor, Pickering, Holt. Your line is now live.

We appreciate the pricing outlook you guys have given and baked into the guide. But curious, should the need arise, is there an ability to further reduce activity without running into contract issues or any other commentary on other actions that might be preferred that could further lower the capital plan for 2024?

Yes, of course, when we construct the capital plan, the first filter is always to generate free cash flow. So we're very focused on that. We're down to two rigs from three rigs. We stacked one of our rigs, so down to the two-rig program and one completion crew. We just released one of our completion crews. We made it a spot crew. That spot crew does have one pad that it is scheduled to complete in the third quarter, and that's highly flexible and dependent on liquids prices. Also, natural gas prices to a bit, but more liquids prices. So, we do have the ability to toggle lower. That's about $50 million, call it. So you could definitely toggle lower than that. And today's gas prices, which is about a $2.25 strip, we're still generating free cash flow. So that's quite amazing. And it's really due to the liquids prices and the capital efficiency, and I mentioned the liquids prices do add about $1.10, $1.15 right now on top of that $2.25, so really driven by the liquids prices. And so we'll continue to monitor those and really focus on generating free cash flow.

Great. And a second question. We were hoping you could provide some commentary on the potential upside to volumes heading toward the Shell facility. And if that materializes, what it could mean for the product mix as we progress through this year?

Yes. No, we're just assuming flat to last year. I mean our ethane guidance is around 70,000 barrels a day, and that's where we were at last year. That assumes Shell performs like it did last year, which is kind of in the low teens. So not really thinking about increased ethane volumes around that, and it's not material on the pricing. It's a Henry Hub-based price. So it's very similar to what we get if it remains in the stream. We have a little bit of a volume tailwind if it performed better than last year, but not baking that into the guidance.

Your next question is coming from Roger Read from Wells Fargo. Your line is now live.

I'm going to come back to a question I asked in the last call in the third quarter and the charts here, Page 3 is probably the best example. Just continued improvements in D&C efficiencies. Looking at your past performances, right, 16 stages in a day or the cycle times reduced to 122 relative to the averages for both without asking can you achieve those best-case scenarios on a regular basis going forward? What was the difference between, say, the average and the best performance? Is that a seasonal thing? Is it just good luck? I was just curious kind of the difference between the two and maybe help us think about how we bridge the gap between those two continuing D&C efficiencies.

It's really about increasing the hours we spend on completions. When we exceed 20 hours a day, we typically achieve 13 to 14 stages. On days when we reach 16 hours, we see much lower pump maintenance and greater pumping hours. In 2023, we consistently reached high teens in pumping hours and achieved 12 to 14 stages a day. Occasionally, we faced issues, but that resulted in an average of 11 stages per day, which was impressive compared to our previous average of eight to nine, as outlined in our guidance. Regarding drilling, we are drilling laterals that are 2,000 feet longer in 2024. This enhances our already impressive performance, reducing our drilling days from about seven days per 10,000 feet down to five, as we continue to drill longer laterals, which positively influences those averages.

Yes, it's been amazing what everybody has been able to do the way you all are leading in definitely impresses...

Yes, we're up over 15,000 feet per lateral in 2024, which is by far our highest in the Company's history.

Yes. Well, one of these days we get gas prices to agree with us on the other side. And along those lines, what is the right way to think about the use of cash going forward? Obviously, you should get the balance sheet where you want it this year, if it's not already. Once that's done, dividend, share repo, variable dividend, what is the way you want to think about the return of excess cash going forward?

Yes. Like we said, first is to continue to pay down debt. We paid down debt in the fourth quarter with our free cash flow, and we'll do it with our free cash flow in the first quarter as well, getting it down to the credit facility. At year-end, we had close to $420 million, $430 million. So that would be the first use of our free cash flow. Then we have 2026 in the $100 million range or all approximate numbers, but also can be included in that credit facility amount. So that kind of gets you down to the $1 billion debt level. And then once that's achieved, we said the majority of free cash flow will go to share buybacks. We tend to favor the share buybacks at these levels at these valuations. So that's kind of the order of the free cash flow use, pay down debt for the next $0.5 billion, and then the majority after that goes to share buybacks.

Our next question is from Nitin Kumar from Mizuho Securities. Your line is now live.

I guess, certainly appreciate the work that you've done on improving capital efficiencies for 2024. If I could maybe delve into what does 2025 look like, right? So you had pretty strong momentum going into the end of 2023, you're reducing activity. Just trying to understand, without looking for guidance, what would the impact of this decline in activity have on your 2025 trajectory, if any?

Not really, Andy, it's the maintenance capital level. When we think about maintenance capital, it's 3.3 to 3.4. We obviously outperformed last year with the completion efficiencies and cycle times. We are better than we had forecasted. Now that we've wrapped those efficiencies into our forecast going forward, it's very similar to this year, holding that 3.3 to 3.4 Bcfe per day in the $700 million range.

Got it. That's helpful. Paul, when you started the Company, you certainly targeted the LNG corridor and where we're strategic in sort of signing up for firm transportation to the market. Really good slide on the power gen market here. Any opportunities to link up with those demand centers with long-term contracts that could kind of certify your realizations?

We've looked at those. They come with fairly hefty commitments. We've already made the commitments. As you know, it's all that firm transport that we control and have for quite some time. So we've kind of achieved those prices through our firm transport commitments and think we will be the beneficiary of those. They will accrue to us. We're all spot pricing, and we're not signing up for any Henry Hub type deals long term. We're just going to flow our gas down to this corridor and let people compete for it, and we'll see what the price is, but we think we'll realize a lot of that uplift without having these kinds of international linked pricing.

Our next question is coming from Neil Mehta from Goldman Sachs. Your line is now live.

Congrats on the improvement in capital efficiency and the guide. Just a macro question. I guess the first one is on propane. Can you talk a little bit about Slide 5 and what do you think has been the main driver of getting the inventories back to the five-year? And as we think about propane markets, Asia continues to be really important and sometimes harder for us as an investment community to get visibility out there. So talk about how you think about China and Asia feeds into the propane ounces of 2024.

I would like to discuss the propane inventory levels. Firstly, there was an unexpected adjustment from the EIA. They had been miscalculating propane inventories since mid-November until about mid to late December, which resulted in an overstatement. This led to an initial positive adjustment, and as we entered January, exports remained strong through December and January, along with some cold weather conditions. We experienced approximately 1.5 weeks of cold weather, which caused some production losses while domestic demand stayed robust and the export docks remained unaffected. This is reflected in the chart, highlighting the December adjustment and some favorable data in January. Currently, we are observing trends closely aligned with the five-year average. If this persists, we anticipate ending the withdrawal season in the 45 million to 48 million barrel range. Transitioning from the top of the five-year range to the average changed the narrative regarding propane stocks, which were perceived to be in crisis, a notion we did not share, and we are glad that the situation has unfolded positively. Regarding the international perspective, we previously had a slide showing continuous demand growth for propane in China, while utilization rates declined due to significant additions in PDH capacity, which we have indeed witnessed. PDH utilization is currently in the 60% to 65% range. Low petchem margins in the East are expected given the surge in capacity. On a broader scale, total demand continues to rise. We remain hopeful that this capacity will be utilized as the economic situation improves, particularly in China, which has not rebounded as quickly post-COVID reopening as many anticipated. We foresee potential growth there, although the U.S. may not be able to meet all demand instantly, depending on whether Gulf Coast stocks can expand timely. We believe the demand will become prominent in 2024, and while not all can be sourced from the U.S., we will benefit from our capacity running out of the East Coast. Additionally, we are observing growing ResComm demand internationally, although this is less visible and requires time to assess, focusing on developments in individual countries related to import terminals. However, the clear trend is the ongoing petchem expansions, which have indeed led to higher demand, even with the reduced utilization rates caused by the new capacity.

Yes. That's really helpful. And then on the dry gas side, recognize your more liquid storage that you might have the most objective view on this, but we've been really surprised at U.S. production. It's great showing it month to date, close to 105 with 2Bs up in the Permian and 2Bs in Appalachia. What do you make of that? And do you believe this data and to the extent that U.S. production is surprising to the upside, what's driving it? And how does it resolve its side?

Yes. We had anticipated that after the decrease in rig counts starting last May, we would see a response in production within a 9 to 12 month period, which is typically the timeframe needed to adjust to a high rig count. However, we have not observed that response; in fact, we’ve seen the opposite, which has been surprising. We hope there will be one last surge in gas production. Historically, Appalachian gas production increases during the winter months due to higher demand, but then it tends to decline into the shoulder season. We hope that pattern continues and that we see lower rig counts in the Permian and oil-producing regions, which may influence the market. However, regarding the expected 105 Bcf market, it may not truly reflect that amount. We could see shut-ins due to decreased activity levels or reduced gas production as we move through the shoulder season, which will affect market balance. Only time will tell if the 105 Bcf holds.

Next question is coming from David Deckelbaum from TD Cowen. Your line is now live.

I wanted to mention the NGL growth heading into '24. It seems there may be some positive impacts from the ethane side. Could you provide some insights into what factors are contributing to that NGL growth? It appears you are focusing more activity on the NGL heavy corridor, yet you're completing about 10% fewer lateral feet this year. Is this due to better well performance, or is it mainly from the additional contributions from ethane processing?

No. As we said, we're really just flat. I mean when you kind of look at it, David, I think we're up 2%. That's just continued focus in the 1,275 to 1,300 Btu corridors that continues to be more and more of our well count those type of wells. Your gas declining, I mean that's kind of the more of the story. We're allowing that gas to decline 3% but growing the liquids a little bit, that maintenance capital calculation. But you've kind of seen that last year when we grew in '23, it was really NGL growth. We grew 14% on the liquids and gas was only up 2%. So it's kind of just a natural outcome of really focusing on the 1,300 Btu type liquid wells and just letting the natural gas, the drier areas of our field decline.

I appreciate that. I guess if there was a scenario where you were to get back to three rigs and two completion crews at some point in the future, would that inherently lead to just a greater gas mix in the portfolio? Or should we be thinking about the mix that you're looking at in '24?

Not initially. We got the liquid inventory day for 10 years. After 10 years, yes, it would be dry gas. But for the next 10 years, this is a good kind of mix where we're at. So the three rigs would have similar outcomes to last year where you grow the liquids and probably the double-digit raises but the gas is flat.

I appreciate that. And if I could just sneak one in. Just the reduced land budget this year, is that intentional restraint? Or is it just more limited opportunity after you guys were very successful there last year?

No, it's a result of our completion efficiencies and development. When you drill fewer wells each year, maintenance capital decreases; it was down to $50 million this year from last year's $75 million to $100 million. There’s a significant land component where we aim to build up working interest and NRI over the next couple of years. With fewer wells during this period, there's less land. We are the consolidator of the liquids fairway in West Virginia, making it challenging for anyone else to capture those locations. We have a contiguous midstream operation, and we're leasing these locations nearby, reinforcing our position as the natural consolidator. The opportunities remain; however, we will have fewer wells in the next two years since we are only operating a few rigs and one completion crew.

Next question is coming from Kevin MacCurdy from Pickering Energy. Your line is now live.

Congratulations on the well-received 2024 guidance. I just have one question, and it's kind of a follow-up to the gas macro question that was asked earlier. In your opinion, how do you think the gas markets get solved? Do you have an opinion of where or who will be shutting in gas production or where the production declines will come from?

What should come from across all natural gas basins because at today's strip, I don't think there are many natural gas plays that are economic. You have to have liquids like we have to make any sort of economics in today's gas price environment. I would say any basin that doesn't have liquids and also where there's a substantial basis and there's no real takeaway. So that's pretty much all natural gas stations right now probably should have less activity. So I think that will naturally occur because economics at the end of the day always win out. So I think that will occur. I think the liquids plays will continue to see activity. But if it's a dry natural gas play that's constrained, it's most likely going to have lower activity. Plus, as we go into the shoulder season and whatever, you always see kind of economics dictating some shut-ins. So, that 105 Bcf, although on a spot day-to-day, seems like it's there. Over time, you'll see some occasional events that will decrease that.

We reached the end of our question-and-answer session. I'd like to turn the floor back over to Brendan for any further closing comments.

Yes. Thank you for joining us on today's call. Please reach out with any further questions. Thank you.

Thank you. That does conclude today's teleconference and webcast. You may disconnect your line at this time and have a wonderful day. We thank you for your participation today.