AR - NYSE

Greetings, and welcome to the Antero Resources First Quarter 2024 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce Brendan Krueger, Vice President of Finance and Treasurer of Antero Resources and Chief Financial Officer of Antero Midstream. Thank you. You may begin.

Good morning. Thank you for joining us for Antero's First Quarter 2024 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.

Thank you, Brendan. Good morning, everyone. I'll start my comments on Slide #3 titled, "Drilling and Completion Efficiencies." As I started my comments off last quarter, the year 2023 was a transformational year for Antero for operational efficiency gains. This year, 2024, continues that trend. Starting with the chart on the top left-hand side of the slide, days per 10,000 lateral feet drilled averaged 5.4 days during the first quarter, down from 5.5 days in 2023. On the completion side, we averaged a quarterly record of 11.3 stages per day during the first quarter, an increase from the pace in 2023 of just under 11 stages per day. These operational improvements result in shorter cycle times, as shown on the bottom of the page. Our year-to-date cycle time per pad is currently trending ahead of last year's 2023 average. There are many inputs that lead to these operational improvements as every single line item gets examined by our team. However, the most impactful change in 2024 has been improved efficiency in zipper swaps that allows us to move from well to well on a pad without having any true downtime. We estimate that this new completion technology will save more than an hour of pumping time each day and will result in further increases in completion times. Our operations also benefit from Antero Midstream's water infrastructure, providing industry-leading water deliverability rates for our completions. Avoiding the use of water trucks significantly reduces pad site congestion that we would otherwise get from water and sand trucks accessing the pad, something that many of our peers have to contend with. Now let's look at how these improvements led to our peer-leading capital efficiency. The chart on Slide #4 compares capital efficiency of the natural gas peer group. Put simply, this is the amount of capital required to achieve a maintenance level of production. Antero has the lowest capital per Mcf equivalent of its peer group at just $0.55 per Mcfe. This is 40% below the peer average of $0.90 per Mcfe. Our best-in-class operating efficiency, combined with significant liquids exposure, led to positive free cash flow during the first quarter and is expected to generate free cash flow for the full year. Now to touch on the current liquids and natural gas liquids or NGL fundamentals, I will turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Cannelongo for his comments.

Thanks, Paul. The start of 2024 demonstrated improved fundamentals for liquids. Ongoing geopolitical tension, particularly in the Middle East, has increased the risk premium on crude pricing in 2024 year-to-date. Internationally, the canal related challenges seen last year have diminished, but global geopolitical tensions remain high. On the domestic front, record propane demand occurred simultaneously with significant January freeze-offs drawing down storage and resulting in upward pressure on propane prices. Propane as a percentage of WTI has averaged 44% since the start of this year compared with 36% in the fourth quarter of 2023. The Exports have remained a driving force in the propane market and are showing strong year-over-year growth driven by growing global demand. This year, China PDH build-out continues to progress with 3 new facilities placed in service in the first quarter and another 3 expected to start up there in the second quarter totaling nearly 170,000 barrels per day of capacity additions in the first half of 2024. At the same time, propane exports have averaged 1.8 million barrels per day in 2024 year-to-date, an increase of 14% over the average in 2023. Notably, propane exports reported an all-time record high this week at over 2.3 million barrels per day. This export growth is depicted on Slide 5. The chart illustrates that the U.S. remains the most important source of waterborne export LPG to meet fast-growing global demand. As a reminder, Antero exports over 50% of our C3+ production skewed heavily towards propane directly out of the Marcus Hook terminal in Pennsylvania. This year, we have elected to sell a greater portion of our waterborne barrels against international indices as well as in the spot market instead of entering into longer Mont Belvieu link term deals. In the event that Mont Belvieu propane prices disconnect from Europe and Asian pricing due to dock constraints or rising domestic storage levels, Antero is well positioned to avoid additional Mont Belvieu exposure. The strength in international pricing has allowed us to increase our guidance for full year 2024 C3+ differentials to a premium to Mont Belvieu pricing. As Paul just touched on, our first quarter results benefited from our significant exposure to liquids prices. Slide #6 illustrates the approximately 125,000 barrels per day of C3+ NGLs plus condensate that we produce. You can see the breakout of those products in the barrel on the left. The barrel on the right-hand side of the slide separates the approximately 40,000 barrels per day of liquids that are closely linked to WTI oil prices. This includes IsoButane, natural gasoline and condensate. Butane markets have also been a strong tailwind to Antero's C3+ realizations mainly due to implications of the Tier 3 gasoline specifications enacted in the U.S. Many U.S. refiners are unable to desulfurize gasoline down to 10 parts per million without also downgrading the octane of their motor gasoline. As a result, there is a strong demand for octane enhancement products made with butanes as feedstock. IsoButane has been particularly strong as it is used in the production of alkylate, which is a key octane enhancement product. Just this morning, you've seen IsoButane trade at over $0.40 per gallon premium to normal butane. In conclusion, Antero's NGL strategy, product diversification and pricing is distinct when compared to other producers. Supportive fundamentals witnessed this past quarter illustrate the promising signs that are ahead. 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'd like to open it up by turning to Slide #7 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, in the Tier 1 pricing points in the vicinity of the major LNG facilities. With several new LNG facilities starting up over the next year, we expect to see a widening spread between sales points near Henry Hub and sales points outside of this premium market. The blue call out box highlights a recent quote from a research commodity team that emphasizes this view. They believe sales points within 100 miles of Henry Hub can see prices comfortably above $5 per MMBtu, while sales points outside of that range could price at $3 to $4 per MMBtu. Looking closely at this map, the yellow stars highlight Antero sales points and are located well within this 100-mile range to Henry Hub. These sales points were strategically selected beginning over 10 years ago in order to access the feeder lines at the doorstep of the LNG fairway. The chart on the top left-hand side of this slide highlights that Antero sell 75% of our gas at Henry Hub link prices while our peers, on average, sell less than 15% of their natural gas into this premium market. Looking ahead over the next 2 years as LNG export capacity increases by nearly 6 Bcf per day, in addition to an expected rise in NYMEX pricing, we expect Antero sales points to be priced at even higher premiums than NYMEX as these LNG facilities compete for supply. An example of this is the pricing along the TGP 500L pool in the summer of 2025 and 2026. We launched those summer premiums increased to $0.40 about Henry Hub on a financial basis alone in anticipation of Venture Global's Plaquemine facility start up in the next few months. Just last year, those same implied summer premiums were only $0.03 above NYMEX. Venture Global received FERC approval this week to begin immediately introducing gas into the feeder Gator Express pipeline that brings supply from the TGP 500L pool to the Plaquemine LNG facility. This initial feed gas requirement will potentially lead to higher demand and pricing in the TGP 500 region as well as NYMEX Henry Hub prices this summer. According to Market Intelligence, the Tennessee Gas Pipeline Phase 1, Evangeline Pass project that feeds the Plaquemine LNG facility, is expected to be online by July 1, 2024, with capacity of $900 million per day. As a reminder, Antero funds $570 million per day of the firm delivery to the 500L pool or 63% of the supply that will feed the Phase 1 project capacity. Next, I would like to touch on the outlook for power burn demand. The chart on Slide #8 depicts a third-party estimate for the increasing natural gas power demand as a result of AI data centers, crypto mining and electric vehicles. It projects nearly 8 Bcf of incremental natural gas demand through 2030 in its base case scenario or 14% growth per year. Next, turning to the chart on Slide #9. We illustrate the significant expected natural gas demand growth coming from LNG exports, Mexico exports, along with this increasing electric power generation need. Combined, these are expected to result in an increase in demand of 30 Bcf by 2030, an increase of over 100% from the same demand sources today. It is in the early innings of increasing electrification demand. 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 grade, combined with rising LNG and Mexico exports, creates a significantly higher base demand level than we have ever experienced in the past. 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. I'd like to start with Slide #10 and our continued focus on reducing absolute debt. We plan to allocate future free cash flow to paying down the remainder of the credit facility balance and the higher coupon near-term notes we have outstanding. We will then be in a position to return to our 50-50 strategy of 50% of free cash flow going to debt reduction and 50% going towards our share repurchase program. Turning to Slide #11. This slide compares 2024 free cash flow breakeven levels. We highlighted our peer-leading breakeven price shown on this slide during our last conference call. Our $2.27 breakeven level compares to the average NYMEX natural gas price of $2.24 in the first quarter. Despite the low price, Antero generated an unhedged $10 million of free cash flow during the first quarter. Our quarterly results benefited from low maintenance capital requirements and high exposure to liquids. And as shown on this slide, results in the lowest unhedged free cash flow breakeven price among our natural gas peers. I will conclude my comments today with Slide #12 titled ,"Antero Resources: The "Unconstrained" E&P Company." We believe the differentiated strategy that we built here at Antero is set up for success in today's macro backdrop. We have significant scale with production volumes of 3.4 Bcfe a day and over 20 years of premium inventory. We have integrated upstream and midstream, which provides development reliability and long-term visibility into our program. This is critical in the development of the asset as evidenced by recent transactions in the basin. We have the firm transportation portfolio that allows us to sell 75% of our production to the LNG fairway in the Gulf Coast. Many of our peers lack firm transportation capacity, forcing them to sell gas at discounted prices well back of Henry Hub. The start-up of the Plaquemines LNG terminal this summer is expected to lead to higher prices at our TGP 500 sales point, potentially leading to higher premiums to NYMEX Henry Hub. Lastly, we have the lowest reinvestment rate of our natural gas peer group. This peer-leading capital efficiency drives higher free cash flow conversion. Our low investment rate and high leverage liquids was highlighted during the first quarter when we generated positive free cash flow despite being unhedged at $2.24 NYMEX Henry Hub natural gas price. With that, I will now turn the call over to the operator for questions.

[Operator Instructions] Our first question comes from the line of Arun Jayaram with JPMorgan.

Maybe one for Justin. Justin, given the strong demand growth potential for gas to the end of the decade, I was wondering maybe if you could comment a little bit more on what you see as kind of advantaged molecules from a margin perspective in this kind of environment. Obviously, historically, Appalachia has garnered a discount just given the lack of takeaway capacity in some of the gas-on-gas competition. But would rising demand in that area for data centers, et cetera, could that start to narrow some of the discounts that we've seen for Appalachia gas?

Arun, it's Justin. Yes. So when we look at just the FT 2 Bcf down to the LNG corridor, we see those premiums continuing to gain value versus Henry Hub in the outer years. So we think that our delivery points in our Southeast head station, CGT onshore, TGP 500L will continue to be very strong in terms of Appalachia versus AI data centers, et cetera, and the basis compressing and gaining value back towards Henry. Antero will have that ability to sell local production volumes as well if those prices increase seasonally or in different months of the year because we do, again, have a transport position of 75% to the Gulf. So we can measure that on variable costs, et cetera, and make that decision over time.

Great. Just a follow-up on the liquids marketing front. Dave, you mentioned that maybe you're exporting a little bit more than 50% or so of your C3+ molecules, what kind of flex do you have in the system? And if you saw a greater arbitrage, could you flex a higher mix in terms of export volumes? And maybe just give an update on what you're seeing in terms of shipping rates.

Yes, Arun, we've done that now. This is Dave. We've done that flex, in particular, in the, call it, the shoulder to shoulder season through the summer. So we've -- it will be reported in our second and third quarter results where it shows the amount of volume that we export versus domestic, and those percentages go higher in the summer where we are, at times, well over 80% of our propane in particular, is going to the dock. So we flexed that already. I think there are some ways to take that higher if the market called for it, but we don't have a lot left in the domestic pool during those times of the year to begin with. And then on the freight rates, I mean things have improved dramatically since where we were late last year, you had all the concerns about the Panama Canal and how much that was going to de-optimize the global LPG shipping fleet and what actually happened, what we're seeing is more LPG ships getting through the Panama Canal since that announcement was made. I think first, the canal has been able to move more ships, in general, through the canal than they initially had forecasted when they announced those restrictions. So we've seen now freight rates collapsed dramatically from where we were in the fourth quarter. And that's ultimately allowing prices at the dock to be closer linked to the international price. And we had a large build-out of VLGC vessels last year, over 40 VLGCs. We're kind of waiting for that to have its effect, and you're now seeing that today in the forward freight pricing.

Our next question comes from the line of Subhasish Chandra with Benchmark.

Probably for Dave first. Dave, what do you think on dock capacity is? And yes, I mean, that 2.3 million was a shocking number, are we pretty close? And I guess those propane hedges, you kind of added there show some caution through December. Maybe some updated commentary there.

Yes. I think we are there on the dock capacity, Subhasish. The number, the 2.3 million, I mean it is a bit of a head scratcher that can happen just kind of based on timing of when ships officially loaded. If they kind of fall a minute into the next week, that can certainly allow a number like that to happen. But we ultimately believe that's well above the kind of average rate that you could run across the U.S. dock. So it's somewhere in that 1.85 million to 1.9 million barrels a day of propane because you still have butane that needs to move across those docks as well. So we'll see what they're able to hit this summer. It's sometimes when it's hotter, it de-optimizes their refrigeration a bit. So I think we'll expect to see those docks highly utilize this summer, but I think we're or about the levels of what we expect that they can do until the, call it, the second half of next year when there is some expansion projects on the way from the Gulf Coast midstream players. And then on the hedges, Yes, great question. We've talked about our concerns around propane pricing and kind of a decoupling of Mont Belvieu, if you saw inventory levels rise as a result of these docks being fully utilized. And so we just thought it was prudent to while we do export the vast majority of our propane, we still had some domestic exposure, and we just wanted to be conservative with that and take that risk off the table if we saw things play out similar to what we saw last year when propane was down in the $0.65 per gallon range. I thought it was a wise move at this time.

Yes. But put some context around that's 10,000 barrels a day, which is on 15% of our total propane production because the vast majority gets international pricing.

That's right.

Right. And Paul, I think on the zipper fracs, just curious, the adoption this year versus prior years? And what does it look like for the balance of the year, maybe percent of well count, percent of TILs, something like that. And sort of why it's come about now, whereas maybe another basin has been more common for a while, is the topology things of that nature.

Yes. So of course, Subhasish, there's -- the zipper fracs have been around for quite a while. But earlier, maybe in a more primitive stage, there's been a lot of decoupling iron and re-hooking it up for different wells. And so we've just found a way to be much more efficient on that. And with the flip of some switches and turning out of some valves, we can flip the zipper frac to different wells as we are pumping. So it's become much more efficient, whereas in the past, it would be at least an hour of downtime when we're changing zipper fracs.

And in terms of sort of application here in the early months of '24, how you visit versus, say, last year?

I think it's a development in the last 6 months to a year where we've perfected it. And it will continue on.

Our next question comes from the line of Bert Donnes with Truist.

Just wanted to ask around the data center demand question a little bit differently. You've continued to kind of avoid the temptation to go overseas with an LNG contract. Is there may be a thought process that if we see a data center-driven boost, maybe there's no reason to lead to the U.S.? And does that lead you to maybe trying to lock in a long-term contract in the U.S.

Yes. No, it wasn't around the data centers. It's just around we're the only company that can really get molecule to the docks or to the LNG actual facilities. So we didn't have any need to enter into long-term contracts around that. We've already done our commitments on the pipeline in itself. And so we just wanted to stay floating in retain optionality for us on what that pricing would look like when they have to compete for our gas. But with the data centers, that actually adds more, obviously, demand for that gas. So that competition just continues to grow.

Okay. And no interest in maybe boosting legacy Northeast volumes for a long-term contract or anything direct, you'd rather just say indirect for both kind of uplift?

Yes. Yes. That's our philosophy, stay in the Gulf Coast. I mean, an interesting thing that it was highlighted in our prepared remarks, TGP, that 500 line we talked about. This time last year, what is that a $0.03 premium for next year, and now it's at $0.40 that is going to continue to go higher. So as it gets closer and closer, you're going to see the premiums continue to go higher in the Gulf Coast, and that's where we sell our gas.

Great. And then changing gears. On the Marcellus rates, on a per foot basis, it was surprisingly strong quarter-over-quarter they were shorter laterals. Is there may be some logic going on that the shorter laterals are more economic and maybe 18,000-foot laterals are a little bit too long? Or is that just -- it's one data point and not shifting gears?

Yes. I'd say it's one data point. Generally, the longer laterals are more economic to spread the cost around longer lateral foot, but we're so good drilling and completing these the longer lateral still provide the economics that it would suggest.

So maybe on the tail end, there will be a stronger later dated production from the longer laterals?

Yes. I mean, I would say, a shorter lateral will clean up more quickly, will dewater more quickly. And so it will get to peak rate in a shorter period of time. But over the longer run, as Mike just said, the economics are so much better when we're going out to 16,000, 18,000 and even 20,000 feet. Those are really big wells. And so you wait a little longer until you get to peak rate, but it's worth it.

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

I had a couple of questions on capital allocation. The first one on Slide 10, you've done a great job of getting your debt down to this level, and you talk about the next area to deploy free cash flow is to pay down your credit facility balance. So maybe curious on your perspective of how shareholder return specifically buybacks fit into this equation. And given the strengthening of the balance sheet, when do you think you're at that inflection point to buy back stock?

Yes. I said in the remarks, the first call on that free cash flow is to pay down the credit facility and that near-term maturity in '26. So that's about $500 million. And then after that, we'll return to our 50-50 strategy of paying down debt plus buying back shares. It will depend on commodity prices when we actually achieve those. But based on today's commodity prices, it'd be in the first half of next year.

Helpful. And then we've seen a lot of consolidation across the E&P space, across energy space broadly. You have a really deep inventory. So I would just love your perspective on how do you see Antero fitting within the M&A landscape? And is the right strategy and organic strategy?

We do believe the right strategy is the organic strategy. You saw we were able to add, I believe, 19 locations in the first quarter, we had $26 million of land. That's highly economic compared to how much locations go for in the M&A landscape. So -- and we continue to consolidate our areas of operation right where we're drilling these terrific wells and just continue to build out our position in the liquids portion of the Marcellus. So we believe that's the best way to add value and continue to increase our 20-year inventory position.

Our next question comes from the line of Jacob Roberts with TPH.

Dave, I wanted to circle back to the liquids market, and I apologize if you did hit on this in your answers, I may have missed it, but I was hoping you could comment just on storage levels at the moment. Specifically, them being above the 5-year it appears as well as the production coming out of PADD 3 and just where do you see those playing out through the summer?

Jacob, this is Dave. If you go back to the first quarter, we actually had that polar vortex in January went from the top of the 5-year range to the 5-year average and then kind of continued along that trend until the last 5 or 6 weeks, we've had I would say some pretty unusual EIA data. It didn't really change at all for 1 month, 1.5 months, and then we had significant change last week and then a below expectation build this week. So we are back kind of in that between the 5-year range and the top of the range below last year, but above that 5-year average. And we'll see what the inflection point looks like, how does that slope rise over the summer. I think there's a lot of different forecasts out there on propane production this year. Hard to say exactly who's right on that. We do pay attention to the rig count in all the basins and watch that. And so that's, again, part of what drove our earlier comments on just taking that small amount of domestic Mont Belvieu propane exposure we have doing some hedging there this year. But sorry, I answered all your questions there, Jacob?

Yes, that's perfect. I appreciate it. And just a second question. Can you remind us on the current expected time line of the Martica payments when those thresholds will be hit? And what that ultimately looks like once they are threshold is met?

Yes. As you rightly recall, they've actually -- they no longer participate in our wells that ended March 31, 2023, but there is kind of that runoff of the PDP base. That does revert back to us when they hit certain rates of return. And right now, we're forecasting that to be starting in '26.

Our next question comes from the line of Kevin MacCurdy with Pickering Energy Partners.

We appreciate all the details you gave on the NGL marketing in the prepared remarks, but my question is, as it relates to your realized prices, it looks like your C3+ prices were much better than the weekly average benchmark pricing. And just curious if there were some onetime items that benefited you in the first quarter versus the benchmark? Or do you expect that premium to continue?

Yes, there aren't any onetime items. We've really switched this year to more international exposure, better contracts, not linked to Mont Belvieu. So we're still kind of working through those relationships Obviously, the international pricing has been better than domestic pricing. And as that continues, we see a higher NGL realizations. You saw that in our increased guidance, increased it by $1. So as we continue to kind of watch the actuals versus kind of our forecast, we'll get a little more dialed in on that. But it's really just due to us switching to internationally linked liquids contracts versus domestically linked in prior years.

Great. And as a follow-up, we've heard from other gas companies that are changing their activity plans given kind of the weak spot prices, what would make you consider pushing out wells until later in the year? Or are you overall happy with the equivalent price you received?

Yes, it's really dominated by liquids pricing. I mentioned on prior calls, we do have one pad. I mean we're only running 2 rigs and 1 completion through. We do have 1 pad in the capital program that's a spot we have had for the third quarter of this year, and that's one that's still to be determined. If it was based on current month prices today, that was one that would potentially be deferred and then that would put you at the low end of the capital guidance range. The other pad is just one completion line. So running that with our 2 rigs is very efficient, and it's very much 1,275 to 1,300 Btu gas, so very high in the liquids content. So that's what drives the economics. I think in the first quarter of our revenue, 55% was liquids and only 45% was gas. So you can see how much the liquids prices really influences the economics of these wells.

Our next question comes from the line of Betty Jiang with Barclays.

Can you provide a bit more detail on the startup of the Plaquemines LNG? Do we need to see the first cargo loading or same chemical start-up before seeing any material feed gas demand. You mentioned that the TGP line, the 500 line has capacity of 900 M. Just any view on how quickly we could see those feed gas demand reach those levels?

Betty, it's Justin. Yes, so when we look at the data that we have so far on Plaquemine, you're correct, the Tennessee project, the Evangeline Pass project should start up July 1. Capacity of 900, the marketing analysts will be tracking the vessels that will be parked waiting to load. So that will be a data point to watch. The vessels that are showing up to the facility as we approach July, and then we'll see through the nominations into that new Evangeline Pass project. So in theory, once we get to July, the physical gas is flowing, we'll start getting a better gauge of how quickly the liquefaction trains are ramping to at least mechanical completion.

Got it. No, that's helpful. And just following up on pricing. Clearly, your guys' view is that the current future strip prices is not reflecting the dynamic around that hub. Why do you think that's case? And what will be the catalyst to drive that relative hub pricing higher?

So you're referring to the Henry Hub pricing?

The TGP 500 line pricing relative to Henry Hub.

Yes, Betty, we are seeing the price reaction at 500 in the forward markets that's just looking at financial basis alone. So looking at financial basis alone, in the summers on Cal '25 and Cal '26 are already showing plus $0.40. That is, again, just financial. So those points will command a physical premium, which we'll start to develop as we get closer to delivery but there will be a physical premium component as well. So if it were $0.10 to $0.20, let's say, you're now at $0.60 or $0.70 over Henry Hub as that physical gas starts to price closer to delivery.

Got it. And is there a physical gas -- physical premium today for the gas?

Today -- it varies, Betty. We've seen different premiums. Last summer, we were seeing very high premiums in the summer months on the physical side, and that's because there still is power generation requirements in the Southeast when the temperatures get hot and AC load starts to increase. So yes, we have seen those premiums in the past, but it can trade flat to plus.

Got it. That's helpful. If I could turn to question just on the certified gas side, it's good to see that you guys increased the certified gas coverage under Project Canary. Do you expect all of your production to get certified at some point? And also kudos to you guys on the emission intensity on the production that's really low relative to your peers. Is there much more room you can do to reduce emissions organically from here?

Yes. So on your first question on Project Canary, we do see that going across all of our fields. We're up to 2 Bcf a day. So it's about 2/3, maybe around 50% of the field on a gross basis. So, overtime, we do see it continuing to build that out across our entire field. On the emissions, we're getting close to being as low as we can. We've eliminated probably about 85% of all our new mag devices and have done all the valve control work that is necessary to limit the emissions from there. So we're getting as close as we can. We ultimately think we will get down in 2025 into the 225,000, 250,000 metric tons level that we need to offset, and that's why you saw us commence with our project to offset those emissions through our stove top, cook stoves in Ghana initiative.

Our next question comes from the line of Subhasish Chandra with Benchmark.

Back to Plaquemine and TGP 500. So obviously, the forwards are showing the scarcity of gas beginning with full ramp in the LNG facility. How do you see that being addressed and over what time frame? Is there absolutely no chance of having incremental capacity there over the next couple of several years that, that premium shows in the strip?

There could be other volumes drawn to that area. Just depending on the basis spreads and the premiums. That corridor has a lot of pipes that traverse west to east, filling that Southeast power generation load, et cetera. So I think to Mike's point earlier, it just depends on the competition of need seasonally and monthly. If global spreads and global pricing are spiking, then you would assume that the competition will increase. There is a finite amount of gas that can get into those areas. So Antero, when we started picking up that capacity years ago or at least putting the contracts together prior to in-service date, we knew at the time that to get physical gas on the 500 leg, it is a challenge to get volume over there just with the market pull in the Southeast. So then you add the new liquefaction facility of potentially 3.4, 3.8 Bcf a day, it just leads to that competition that we expect and volatility and then price premiums.

There are no further questions in the queue. I'd like to hand it back to management for closing remarks.

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