Antero Resources Corporation

Welcome to the Ontario Resources 2020 Fourth Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. Anyone should require operator assistance during the conference, please press star zero on your telephone keypad. Please note this conference is being recorded. I will now turn the conference over to your host, Michael Kennedy. You may begin. Thank you.

Thank you for joining us for Entero's fourth quarter 2019 investor conference call. We'll spend a few minutes going through the financial and operational highlights, and then we'll open it up for Q&A. I'd also like to direct you to the homepage of our website at www.enteroresources.com, where we've provided a separate earnings call presentation that will be reviewed during today's call. Before we start our comments, I would first like to remind you that during this call, Antero management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero and are subject to a number of risks and uncertainties, many of which are beyond Antero's control. Actual outcomes and results could materially differ from what is expressed, implied, or forecast in such statements. Today's call may also contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations for the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman and CEO, and Glenn Warren, President and CFO. I will now turn the call over to Paul.

Thank you, Mike, and thank you to everyone for listening to the call today. In my comments, I'll begin with an update on the continued momentum around our internal cost savings initiatives, including our lower well-cost targets for 2020. And then Glenn will highlight our balance sheet and liquidity position and provide a brief update on our ongoing asset monetization efforts. Let's start by discussing the cost reduction momentum across all of Antero's cost structure. Detailed on slide number three, titled Cost Reduction Momentum, nearly half of these reductions will come from lower well costs as we target almost a $2 million per well cost reduction in 2020 relative to our initial 2019 capital budget. This equates to roughly $240 million in total well cost savings, assuming our budgeted 125 completed wells in 2020 with an average lateral length of 11,400 feet. Lower midstream fees, net marketing expense, LOE, and G&A make up the remaining savings of approximately $280 million. In total, we expect our cost structure to be reduced by $520 million in 2020 as compared to 2019. Now, let's move on to slide number four, titled Marcellus Well Cost Reductions, which provides an update to our Marcellus well cost targets. Driven by expanded flowback water blending operations, As continued step change improvements in our drilling and completion efficiencies, we are now targeting a reduction of 15% to 18% or $1.7 to $2. million per well. The left-hand side of the page illustrates AR's January 2019 budgeted well cost at $970 per lateral foot. As we exited the fourth quarter of 2019, AR's well costs were approximately $840 per foot, which equates to $1.5 million per well of savings achieved as compared to our initial 2019 budget. This also represents $55 per foot improvement from our previously targeted fourth quarter 2019 AFE. These accelerated savings were primarily driven by drier completions, enhanced drill-out technology, and lower costs of flow-back water as Antero Midstream implemented water blending and localized storage operations. The coordinated effort between AR and AM allowed us to quickly and successfully execute our blending program and deliver savings ahead of schedule. Looking ahead in 2020, we are targeting a well cost range of $795 to $825 per lateral foot, which will be driven by implementing dryer completions in 100% of our wells, expanding produced water service through AM's pipeline system, and further drilling and completion efficiencies. Slide number five, titled Significant Reduction in Operating Cost Structure, illustrates how material these cost savings are on a unit cost basis. We expect 2020 all-in cash expense to be $2.30 per MCF equivalent, which is 22 cents lower than the full year 2019 guidance. We're forecasting an 11 cent per MCFE reduction in LOE, G&A, and GP&T, or gathering, processing, and transportation. But the biggest driver is an 11 cent decrease in net marketing expense. This substantial year-over-year reduction is due to a combination of higher production volumes and renegotiated terms with third-party service providers that allow us to optimize more of our premium-priced firm transportation. As we grow into our firm transportation portfolio through 2021, We anticipate further reductions, bringing our all-in cash expense to $2.10 per MCF equivalent in 2022. In 2022, we expect net marketing expense to be $50 million per year, or just $0.03 per MCFE, as compared to over $250 million, or $0.22 per MCFE, last year. Our reduced cost structure will provide us with flexibility and allow Antero to generate sustainable free cash flow in 2022 and beyond at current strip prices. Now, let's turn to the operational side by turning to slide six, entitled Marcellus Drilling and Completion Efficiencies. as we continue to make improvements on cycle time. For 2019, we averaged 5934 lateral feet drilled per day, a 30% increase compared to 2018. During the fourth quarter, we set new records for average lateral feet drilled per day, averaging 7000 feet per day and set another new one well world record drilling of 10,453 lateral feet in one day. The quarterly average represents a 17% increase in lateral performance from the prior quarter and a 38% increase compared to the 2018 average in lateral performance. Further, the reduction in fresh water used in our completions helped increase our completion stages per day to a new quarterly record of 6.3 stages per day, an increase of 7% from the prior quarter. In summary, our cost reduction efforts have already delivered significant results. Our fourth quarter DNC spend was $300 million, And our full year 2019 DNC spend was $1.27 billion, a 14% decrease from 2018. Our 2020 DNC CapEx budget of $1.15 billion is 10% lower than 2019, while still delivering modest production growth of 9%. highlighting the improving capital efficiency of our asset. These savings, along with our industry-leading hedge position, support our modest growth strategy through 2021 as we fill our premium unused firm transportation commitments. It is important to note that this program is projected to be cash flow neutral in 2020, based on today's commodity strip and including the $125 million water earn-out payment that we received in January of 2020. With that, I will turn it over to Glenn for his comments.

Thanks, Paul. Turning to slide number seven, titled Substantial Liquidity Enhancements, I'd like to start with Ontario's liquidity position and discuss how we're thinking about upcoming debt maturities. in November of 2021 and December of 2022. In early December, we announced a three-prong approach to address these upcoming debt maturities. The first two shown at the top of the slide, internal cost reductions and midstream fee reductions, have already been specifically detailed. As Paul just highlighted, our cost reduction initiatives are projected to reduce our all-in cost structure by approximately $520 million in 2020. as compared to 2019. These savings combined with the water earn-out payment and our robust hedge position lead to a free cash flow neutral profile in 2020, even at today's depressed commodity price strips. The third part of our strategy is targeted asset sales. As previously stated, we are targeting $750 million to $1 billion in asset sales in the year 2020, with proceeds being used to reduce absolute debt. The chart on that page shows our liquidity outlook starting with our liquidity position at year-end 2019 of $1.5 billion. As I mentioned before, we expect to be cash flow neutral in 2020, so as you can see, the successful execution of our asset sale program will significantly enhance our liquidity position, providing more than enough liquidity to address both our 2021 and 2022 remaining maturities. Illustrated on the right side of the chart, we were able to repurchase a notional amount of $225 million of our 2021s and 2022s at an overall discount of 17%, effectively reducing absolute debt by $37 million. Now let's review the asset monetization options that we're evaluating. Turning to slide number eight, titled Asset Monetization Opportunity Set, You can see we have a multitude of options available to us. We have 541,000 net acres in Appalachia with 19 TCFE-approved reserves and 12 TCFE-approved developed reserves. We have an 84% net revenue interest in our leasehold, well above most of our peers. Our hedge book, while always core to our company's strategy, could be restructured to bring forward a portion of the approximately $1.1 billion in value that it holds today. Lastly, we own 28% of Antero Midstream with a current market cap of roughly $685 million. That's the market value of the AM that we hold. Our goal is to complete our asset sale program in 2020 and reduce absolute debt. Having multiple options gives us great confidence that we will be able to achieve our asset sale proceeds target in the coming quarters. Now I'd like to discuss our NGL realizations for the quarter on slide number nine, as we saw tremendous improvement with regard to our C3 plus NGL pricing. During the fourth quarter, Antero realized a pre-hedge C3 plus NGL price of $29.63 per barrel, $1.26 per barrel premium to Montbellevue. This premium was primarily driven by the recently widened international pricing arbitrage versus Montbellevue that we were able to capture through our committed propane and butane volumes on Baronese II. Looking forward, we are well positioned to continue realizing premium prices to Montbellevue due to our advantage position as the largest NGL exporter in the U.S. and from our access to international markets through Marcus Hook in Pennsylvania. As depicted on slide number nine, Antero Resources' most advantaged NGL producers, Antero is able to capture the international arbitrage versus Mont Belvieu through direct sales into international markets, fixed terminal rates, and local fractionation. This is in direct contrast to producers with exposure to the Gulf Coast who receive Mont Belvieu less pricing due to constrained export and storage capacity in the region and no local fractionization that would enable purity product sales. Looking ahead to the year 2020, we expect our C3 plus NGL price realizations to continue to be at a premium to Montbellevue, providing a truly differentiated NGL story for Antero. Now let's move to slide number 10, titled Well-Protected from Near-Term Gas Pricing Weakness. Antero Resources has a long track record of hedging and selling production forward as we have generated $4.7 billion of net cash hedge gains since the year 2008. For 2020, AR has hedged 94% of its expected natural gas production at $2.87 for MMBTU, or approximately 38% above current strip pricing. AR is also well hedged in 2021 with 93% of expected natural gas production hedged at $2.80 per MMBTU, or approximately 20% above current strip pricing for that year. As you can see on slide number 11, titled Significant Oil and Oil Equivalent Hedge Position, Ontario Resources is 100% hedged on 26,000 barrels a day of 2020 crude oil and pentane production at approximately $56 a barrel. or 10% above current stroke prices. In conclusion, I will round out my comments by directing you to slide number 12 entitled Antero Long-Term Strategy. We have detailed our cost savings initiatives that are expected to extract approximately $520 million from our cost structure in 2020 through lower well costs and reduced cash expenses. Our new well cost target of $795 per foot at the low end is a substantial decrease from the $970 per foot in our initial 2019 budget, so a year ago. These savings are already delivering critical benefits as shown by our capital budget that is 10% below 2019, while still generating moderate production growth. Our modest growth strategy allows us to realize the $75 million in previously announced gathering, processing, and transportation expense savings in the year 2020, and ultimately results in $350 million in total savings between 2020 and 2023. Additionally, by growing into our unutilized firm transportation commitments, we reduce our cost structure by another $200 million by the year 2022. Combined with our liquids focus and world-class hedge book, we are forecasting a free cash flow neutral profile in 2020, despite the deterioration of the commodities drill. Our asset sale program is well underway, with proceeds to be used to bolster our liquidity position and reduce absolute debt, ultimately. Further, through the asset sale program, we will have substantial liquidity available to address our late 2021 and late 2022 debt maturities targets. and to navigate the lower commodity price environment that we're in today. With that, I'll now turn the call over to the operator for questions.

Thank you. At this time, we will be conducting a question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. The confirmation tone will indicate your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the start button. One moment, please, while we poll for questions. And our first question is from David Deckelbaum. Please proceed with your question.

David Deckelbaum Good morning, Paul and everyone. Thanks for taking my questions. I had two primary ones. One, you guys hit some pretty strong drilling records this quarter. Realizing your target, I think, for the year is somewhere in that 6,500 lateral feet per day, I guess, can you talk about what drove that huge increase? Was it just drilling some of the longer lateral lengths and realizing efficiencies there? And where do you see that progressing, I guess, the rest of the year?

Yeah, as we mentioned in this fourth quarter, we averaged 7,000 feet sideways per day, which is a continued increase. And it's really competitive techniques, I would say, that we use to get faster and faster. In our budget, we've been conservative as to amount of footage per day, but there's a very good chance that we'll be able to – exceed even what we achieved in the fourth quarter, that is more than 7,000 feet per day. So really hats off to our drilling department for making such inroads. I think we've compared across all of the shale plays, and we're right there at the top in terms of lateral feet per day. It's a multiples of what some of the other basins can achieve. So we're very, very proud of it. But in answer to your question, I think we'll be able to keep it up and even get faster.

I guess what I'm asking is what's the difference in perhaps that average and the record of that 10,453 feet per day? I guess what was able to be achieved there?

Well, the stars do have to align in terms of being at the right spot in the lateral. If you have a nice long lateral of 14,000 feet, then you're off to the races. You can go 10,443 feet in the lateral within 24 hours, but if the stars don't align and you only have a a 9,000-foot lateral to make that point, or if you're two-thirds of the way through and you only have 7,000 feet remaining, then you can't get those 10,000 feet a day records. So it all has to fall into place. But not many days, as you can imagine. We make the turn at around 6,300 feet, so... There's not that many days spent in the lateral, so you just need to have a nice long lateral with a good run at it.

Got it. And then just the last one for me. You've made some headway, I guess, on some of the transport cost relief out of the firm portfolio. Are you optimistic that there's more room to go there? And I guess what sort of structure are these negotiations taking with some of these firm contracts that you have? Are these just the signs now at lower tariffs or are these being offloaded to other parties and you're trading out of them? Just any color you could provide there.

Yeah, I would say it's – It's not lower tariffs. You know, the tariffs are FERC regulated, so we have offloaded some, and we've announced that, I think, in the fourth quarter. And earlier we do what are called asset management agreements. They're FERC regulated, but AMAs where a third party, a marketing party, might take the transportation path off our hands and pay us a fee up front to do that, and then they can market around it. It's a way for us to recoup a good amount of our demand charges. So that's out there, but as we grow, we'll be filling it all with our own equity gas. In the meantime, it's that, either laying it off or buying distressed third-party gas at the many receipt points that we have and being able to move it and collect the spread and offset the demand charges or at least some of them and be able to fill the unutilized that way and continue to whittle down those costs.

Thanks for the answers, guys.

Our next question is from Wells Fitzpatrick. Please proceed with your question.

Hey, good morning.

Hi, Wells.

Good morning. Obviously, really impressive drilling records you guys are doing up there in the Marcellus. And, you know, needless to say, it's a good problem to have. But does the speed that you guys are putting these things away at now, I mean, does that mean that maybe we should be a little bit more biased to front half-weighted CapEx or possibly even flex down the rig count at some point?

Well, I do think flexing down the rig count at some point at some point for us is possible. We're just, you know, we've made the point before, but years ago, we had a high of, I think, 22 rigs drilling across Marcellus and Utica, and what we can achieve now with four rigs, and it's really three big rigs and a smaller top center rig that gets us down to the curve. It's just amazing what we can achieve with just this. So, Could Antero be able to accomplish as much with fewer rigs someday? Yeah, that's possible. Certainly, we're a leader in the drilling side of things. Will it translate across the industry? Will everybody be able to achieve this? No, probably not, depending on the play and circumstances of everybody's inventory. So it's possible to drop our rig count at some point and maintain our growth, but don't know if it translates to the rest of industry.

Okay. Okay. Makes sense. And then going through the presentation, it looks like the acreage drop by 43,000 to A, am I right comparing that to the last presentation, and B, is that mainly coming from maybe Utica stuff you wouldn't be getting to for decades?

Yeah, it's really explorations kind of around the French that we wouldn't be drilling anytime soon, so we've let some things go here and there, yeah.

Okay, makes total sense. Thank you, guys.

Yeah, thank you.

And our next question is from Jeffrey Lamboujon from Twitter Pickering.

Good morning. Good morning. Just taking my questions. My first one is just on longer-term financing. You know, the free cash flow profile certainly improves year on year, as you guys point out, as you continue to bring down costs. But there still appear to be a gap between cumulative free cash flow generation and some forthcoming maturities as we look out, assuming strip pricing, as is illustrated in the deck. And I know that asset sales are a targeted solution for the 2021s, which would augment the credit facility capacity. But how do you generally think about, you know, not only financing those in the 2022s, but also addressing just the longer-term objective of bringing down aggregate debt?

Yeah, the asset sales obviously bring down aggregate debt. So we're targeting, you know, up to a billion dollars of asset sales, and we may even go beyond that over time. So we'd like to take at least a billion dollars out of our total absolute debt, getting us down into the mid $2 billion range on absolute debt. So that's really our objective there. As far as the maturities go, obviously the asset sales also would address that. We don't have a need to go to the bond market if we're able to execute on the asset sales this year. So we think it's a pretty concrete plan, and you can't shortchange the cost restructuring because You know, these are obviously subdued prices right now. It was kind of a perfect storm here over the last few months around natural gas and then oil and NGL. So I don't think you can take those prices as the longer-term view on price. So we have tremendous leverage to prices. For instance, if we had – with this reset cost structure, if we had just the average prices we realized in the year 2018 – we'd be generating a billion dollars of free cash flow this year. If we look out to 2022, when our hedges have rolled off, if we have $2.75 per MMTU natural gas, and we have, say, $28 per barrel C3+, and I'm assuming kind of a $55 oil price, in those kind of normalized pricing environments, we're throwing off well over $500 million of free cash flow. So prices heal a heck of a lot, but we're not assuming that. We're assuming that we're going to monetize some of the assets and get the overall debt down.

Understood. I appreciate the detail on that. My second one is just around the flexibility around maintenance timing. Is there a scenario in which you consider moving to that type of capital program sooner than what's been laid out in some of the previous decks or assuming the timeline sticks? What's the thought process around considering moving to even declines in the out years, just in an interest of solving for a free cash flow, assuming, you know, strip pricing holds?

Yes, strip pricing, we're just a static, which it never does, of course. But if that's your view on prices, then in 2022, once our hedges are rolled off, we've filled our premium firm transportation. So, you know, we're still in a good free cash flow position there in 2020, 2022 and beyond. So, no plan to, you know, differ from that trajectory that we've laid out. You always have to look at that every quarter, every year in terms of what's my view on prices, how much do I have hedged, but we're in pretty good shape right now. I think the soft spot today is liquids prices, but we are over 30% hedged this year, and we're hedged on the highest value products, which is our pentanes and So we're in good shape this year from a hedge standpoint. And that really gives us the staying power to stick with our budget. So I don't see us differing from that over the next couple of years. But you always have to look at it. What's the current outlook?

All right. Thank you.

And our next question is from Greg Roddy from Bank of America. Please proceed with your question.

Hi, Greg.

Hey, guys. Good morning.

Thanks for the update. Maybe you could provide some – you know, you took your NGL per barrel guidance down, which is reflecting the curve. I'm curious if you can provide some perspective on the NGL market and maybe your thoughts on the freight markets to try to help us think through what we should be paying attention to today for price action.

Yeah, well, I think – What we can say is over the last number of months, let's say before coronavirus, that it was quite a healthy NGL market, that international ARBs, both the Northwest Europe and the Far East, were extremely strong. How do we explain that? Well, there was congestion, I guess we could say, in the Bellevue and the export docks along the Gulf, And so it was hard to clear liquids in the Gulf. We have a competitive advantage in sailing time to Northwest Europe, so we were able to pick up a lot of the market there. But even beyond that, Far East was strong. They were just not getting enough liquids out of the Gulf due to the constraints and congestion there. So very healthy fourth quarter market as – Mariner East, too, has come on and is ramping up its capacity. It's helping to drain the bathtub, so to speak, of the Northeast. That's always been a healthy liquids market until so much liquids came on from the Marcellus. But Mariner East is making a good dent in it. Therefore, we keep about half our volumes fed. to sell domestically, and we sell it at the tailgate of the Hopedale Fractionator, and from there, we can get prices that are getting closer and closer to Bellevue. A year ago, we would have been 25 cents off Bellevue. Now, we're 5 to 10 cents off, and as Mariner drains the bathtub further, we're seeing things there, you know, climbing towards the Bellevue price. So, So for us, with the export market, it's been healthy. A lot of buyers out there. Now, of course, coronavirus has put a blanket on everything, so we've definitely slowed down the last few weeks in terms of price expectations, still moving our volumes, but the international markets are more subdued. But absent that, we're quite optimistic as to the opportunities there to keep moving barrels out of markets up to Far East and Northwest Europe. There's good demand and good world growth.

It sounds like you could also keep more volumes in Appalachia, too, just because pricing is improving there.

Yeah, that's right.

Got it. And maybe just a credit question for you. Obviously, the borrowing-based redetermination is coming up in the spring. Can you give us your thoughts on expectations there? And then also, with the recent downgrades from the rating agencies, you spoke last quarter about potentially having more LC postings. I think you said like 100 to 300 million. Curious if you're still comfortable with that number and how maybe a surety bond market may offset some of that.

Yeah, on the borrowing base, we'll have to see where the bank price decks come out. They'll be out in the next – couple weeks, I think, and we can start to look at that again. Keep in mind that we're so well hedged on the first couple of years, that's really where the likely price action downgrade is from the banks on their strips. So any reduction there versus what we looked at in the fall, you know, is likely muted by the hedge book. So we're not too concerned about that. And We feel confident that we're going to have a billion-dollar-plus cushion above our lender commitments of $2.6 billion. Maybe it's a billion-and-a-half cushion, somewhere in that range. But we'll see how that shakes out. So the good news is we have the borrowing basically well in excess of the lender commitments there. So that keeps us in a great position from a liquidity standpoint. Our liquidity numbers, those are all based on just the current lender commitments, not the total borrowing base, of course. And then...

Yeah, on the ELCs, I think, Greg, you probably noted that we reduced them by $80 million in Q4, down to $623 million. Those downgrades that you mentioned from the rating agencies did increase that amount. We have that amount in our 10-K. Currently, it's at $730 million, so that's the extent of it. So we basically offset the rating agency downgrades with increased surety bonds, and we continue to work on that and are working on other LLCs to replace them with surety bonds. So hopefully we'll have some update for you on that at the end of the first quarter.

So the 730 takes into account all the – Correct. I think you said there were – so you've got that, and you could possibly reduce it more, you think? Right. All right. I'll hop back in the queue. Thank you for the time, guys.

Thanks, Greg.

And our next question is from Holly Stewart from Scotia Howard Whale. You may proceed with your question.

Good morning, gentlemen.

Hi, Holly.

Maybe just first, you guys have talked a lot about the asset sale program. Glenn or Paul, could you just maybe talk about how the A&D market is sort of shaping up right now?

Well, first off, I mean, that's not our primary focus, the A&D market. So we're not out there marketing anything specifically in the A&D market. You know, we've talked in the past about minerals and overriding royalty. We have some discussions there. Beyond that, the other things are sort of outside of that. They're unsolicited type discussions. And, you know, there are big numbers in terms of what we're talking about these days and how much of it gets done. That remains to be seen. But that's kind of All we can say right now, it's gonna take some time and we'll see how that unfolds, but we're confident on getting all that done in 2020.

Okay, fair enough. And then maybe just on the capital spending program for the year, can you just outline some, maybe the trends or the cadence, I guess, throughout 2020 for the spending as well as the sort of production outline?

Yeah, the production is a rattable growth, Holly, up to average at 3.5 from the Q4 2019 on the capital. The capital is slightly a little more in the first and second quarter, as we mentioned, with those drilling efficiencies and our drilling ability. Those four rigs are currently running right now for the first three quarters, and then it's three rigs in the fourth quarter, so slightly down in the fourth quarter. But generally, even throughout, just slightly lower in the fourth quarter of 2020 compared to the other three quarters for capital.

Okay. That's great. And just to follow up on the LC question, so it looked like at year end, you're at 623, and you're saying post the rating agency movement, now you're at 730, and then you'll look to decrease that with further surety bond issuances.

Correct. That's correct.

Okay. Great. Thank you.

Thank you. And our next question is from Aaron Jerem from JP Morgan. Please proceed with your next question.

Yeah, Glenn, I was wondering about your longer-term hedging strategy, you know, looking beyond 2021.

Yeah, I'll let Paul comment on that.

Yeah, so we've made the point, especially on gas, that we're hedge through 21. So, uh, you know, we obviously we've, uh, done well in hedging over the last 10 plus years and we don't plan to stop. That just gives us a lot of comfort, a lot of protection against, uh, price falling away like it has recently. So we're looking out there, but, uh, you know, the prices are not interesting enough for us right now, but, uh, We keep an eye on things every day, every month, and the opportunity will arise. And so we'll do that. We'll be hedging a lot of our gas in Cal 22 and beyond as prices come back, as hopefully they will. And yeah, so that's where our focus is beyond on the gas price, gas hedging pricing. As to liquids, we keep an eye on that as well. And there's still some to be done in the MGLs, but we're pretty solid on oil for this year. And as you know, oil goes up and down, but very liquid and very readily doable on short notice. So we'll watch that as well for Cal 21.

Okay. And I know that you have the asset sales program, a lot of different levers that you could pull. I was wondering, you know, we do have some merchandise. I think EQT does have a process on the mineral side and perhaps their Utica assets. But could you just talk at a higher level what type of interest that you're seeing in minerals? I know Range was able to do – a couple, two, three, uh, asset sales that kind of equated to a 12 and a half times kind of multiple in terms of cashflow, um, as well as, uh, what you're seeing in terms of market appetite for undeveloped acreage, um, uh, or non-cash flowing, uh, acreage, uh, in Appalachia.

Yeah. I just say we have, we see strong interest in all that and, uh, we won't have any color to announce on it until we have a deal to announce. So, uh, That's all I'm gonna say on that at this point.

Fair enough.

Thanks a lot.

Thank you.

And our next question is from Betty Jung from Credit Suisse. We'll see what your question.

Thank you. Good morning. So just looking on the cost side, cash cost came down seven pennies from the guidance given last December. And a lot of that reduction came in GP&T and net marketing expense. So just trying to understand what's the key driver of that reduction just over the last two months.

The key driver is just as our production grows, it fills our capacity We've talked about laying off through asset management agreements any paths that we're not using and get prepaid for it. And as spreads have widened, that is, as the regional pipelines have gotten more and more full, so there's not that much unused capacity. And the capacity that is unused, and I'm talking about industry capacity through Appalachia, Not everybody can reach that. And so the spreads have widened. They've widened to the Gulf, to Chicago. So we're able to buy third-party gas and fill that, transport and collect the spread. And so all of that helps to fill what we have, make the most of our assets, and be able to offset some of those demand charges.

Got it. So, I mean, just given the magnitude of that decline, certainly welcome. Like, are there, do you see more room for that cost to come down? And then separately, like, could we see more relief coming from midstream partners?

I wouldn't expect anything with midstream partners, but with long-haul transport, which is held by By AR, of course, as the spreads widen on the third-party gas or as spreads widen on laying off any full paths and get prepaid, we could see improvement as it becomes more constrained. And as the spreads widen, all of that goes into Antero's interest into our pocket and helps to offset any of that FT. So sure, it can definitely improve

And sort of follow up just on that too, the reduction that we have seen based on optimization of spreads, could that persist beyond 2020 relative to what you guys were thinking about in December?

Yes, you know that, of course. on all pipes. The spreads get remarked every day or even within the day, being that there's four trading cycles in the day. So the spreads are always moving, always changing, but there's always the potential as there's more gas here and more demand there that spreads can definitely improve as they have since the fourth quarter. And so if I'm sure there's definitely potential for that to help us.

Got it. Thank you for that.

Thank you. And once again, if you have a question, you may press star one on your telephone keypad. Our next question is from Tariq Hamid from JP Morgan. You may proceed with your question.

Good morning. Hi, Tariq. Good morning. Just a follow-up on the LCs. Can you maybe just talk a little bit about... you know, the surety bond market, kind of what you're seeing in terms of rate and tenor in that market, just sort of trying to get a sense of kind of the cost of those, how to think about the cost of those moves.

Yeah, the costs are just very similar to the LCs, and they're for a one-year term.

And then a little bit more interesting topic, just on the sort of AM units, you again sort of highlighted them as an asset, and you also highlighted the sort of the AM RP capacity. Could you maybe just talk a little bit about how you think about sort of selling those units to AM versus selling them to a third party? Sort of what's the calculus in your mind between sort of control versus non-control on the buyer?

Yeah, first off, I mean, we're in sort of an enviable position of having time, right? We're not too concerned about having to do anything right away. They're not trading at an attractive price for a sale right now from AR's perspective, I don't think. We'll see how that plays out over time, Eric, but it's something that we'll just keep an eye on. It's not our number one priority right now.

That was literally my follow-up on how do you think about the timing, given that every move you make on AR clearly benefits the AM valuation as well over time. Is that the right way to think about staging of potential sales?

Well, I wouldn't hyper-focus on that. I mean, you know, AM has some appetite probably to buy more shares. It has a program out there, and those shares may be bought from AR or bought in the open market. But, you know, AR is not in a position to – it's not leaning in on selling AM shares right now, I think, is the read. So we can be patient, and it's something we'll look at throughout the year.

Got it. Appreciate it. I'll get back to you. Thank you.

Thank you. Thank you.

And I have reached the end of the question and answer session. And I will turn the call back over to Michael Kennedy for closing remarks.

Yeah, thank you to everyone who has joined us on our conference call today. If there are any further questions, please feel free to contact us. Thanks again.

And this concludes today's conference, and you may disconnect your lines at this time. Thank you for your participation.