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Antero Resources Corp
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Welcome to the Antero Resources 2020 Fourth Quarter Earnings Conference Call. at this time, all participants are in a listen-model. [Operator Instructions] Please note this conference is being recorded.
I will now turn the conference over to your host Michael Kennedy. You may begin.
Thank you for joining us for Antero'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 home page of our website at www.anteroresources.com where we have 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 to the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman and CEO; and Glen 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 Glen 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 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 11400 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 4 titled; Marcellus Well Cost Reductions which provides an update to our Marcellus well cost targets. Driven by expanded flowback water blending operations and continued step change improvements in our drilling and completion efficiencies we are now targeting a reduction of 15% to 18% or $1.7 million to $2.0 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 flowback 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 5 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 $0.22 lower than the full year 2019 guidance. We are forecasting an $0.11 per Mcfe reduction in LOE, G&A and GP&T or gathering processing and transportation but the biggest driver is an $0.11 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 6 entitled: Marcellus Drilling and Completion Efficiencies, as we continue to make improvements on cycle time. For 2019, we averaged 5,934 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 and lateral performance.
Further, the reduction in freshwater 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 D&C spend was $300 million and our full year 2019 D&C spend was $1.27 billion, a 14% decrease from 2018. Our 2020 D&C 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 earnout payment that we received in January of 2020.
With that, I will turn it over to Glen for his comments.
Thanks, Paul. Turning to slide number seven titled Substantial Liquidity Enhancements. I'd like to start with Antero'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-pronged 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 earnout 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 2021's and 2022's and an overall discount of 17%, effectively reducing absolute debt by $37 million.
Now let's review the asset monetization options that we are 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 of proved reserves and 12 Tcfe of proved 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 strategy, could be restructured to bring forward a portion of the approximately $1.1 billion and 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+ NGL pricing. During the fourth quarter, Antero realized a pre-hedge C3+ NGL price of $29.63 per barrel, a $1.26 per barrel premium to Mont Belvieu. This premium was primarily driven by the recently widened international pricing arbitrage versus Mont Belvieu that we were able to capture through our committed propane and butane volumes on Mariner East 2.
Looking forward, we are well positioned to continue realizing premium prices to Mont Belvieu due to our advantaged 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 Producer, 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 received 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+ NGL price realizations to continue to be at a premium to Mont Belvieu 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 per 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. Antero 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 strip 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 reduce 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 saw 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 reduced 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 strip. 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 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. [Operator Instructions] And our first question is from David Deckelbaum. Please proceed with your question.
Good morning, Paul and everyone. Thanks for taking my questions. I had two primary ones. One, you guys had 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?
Yes. 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 compared it across all of the shale plays and we're right there at the top in terms of lateral feet per day. It's multiples of what some of the other basins can achieve. So we're very, very proud of it. But to 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 hence 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 the stars don't align and you only have 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. We have to -- 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. Just you've made some headway I guess on some of the transport costs 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 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?
Yes, I would say it's not lower tariffs. 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 or marketing party might take the transportation path off our hands and pay us a fee upfront to do that and then they can market around it and 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 -- utilize that line and continue to whittle down those costs.
Thanks for the answers guys.
Our next question is from Welles Fitzpatrick. Please proceed with your question.
Hey, good morning.
Hi, Welles.
Good morning.
Obviously really impressive drilling records you guys are doing up there in the Marcellus. And 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 for us is possible. We're just -- 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?
Yes.
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 to the presentation, it looks like that the acreage drop of 43,000 to 541; a, is it -- 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 exploration is kind of around the French that we wouldn't be drilling any time soon. So we've let some things go here and there. Yeah.
Okay. Makes total sense. Thank you guys.
Yeah. Thank you.
Our next question is from Jeoffrey Lambujon from Tudor, Pickering. Please proceed with your question.
Good morning. Good morning. Thanks for taking my questions. My first one is just on longer-term financing. 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 is as illustrated in the deck.
And I know that asset sales are a targeted solution for the 2021's, which would augment the credit facility capacity. But how do you generally think about not only financing those in the 2022's, 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 up to $1 billion of asset sales and we may even go beyond that over time. So we'd like to take at least $1 billion 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 are 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 these are obviously subdued prices right now and there is 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 $1 billion of free cash flow this year.
If we look out to 2022 when our hedges have rolled off, if we have $2.75 per MMBtu 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 environment, we're throwing off well over $500 million of free cash flow. So prices feel 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 time line sticks, what's the thought process around considering moving to even declines in the out years just in the interest of solving for free cash flow assuming sure pricing holds?
Yeah, sure pricing were just a static, which it never does of course, but if that's your view on prices then in 2022 once our hedges have rolled off, we filled our premium firm transportation. So we're selling a good free cash flow position there in 2022 and beyond.
So, no plan to 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 our well.
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 different 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 Gregg Brody 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 took your NGL per barrel guidance down which reflecting the curve. But 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 should we be paying attention to today for price action?
Yes. 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 arms both the Northwest Europe and the Far East we're extremely strong. How do we explain that? Well, there was a congestion I guess we could say in the Belvieu 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, a very healthy fourth quarter market as Mariner East 2 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 the -- we keep about half our volumes 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 Belvieu. A year ago we would have been $0.25 off Belvieu. Now we're $0.05 to $0.10 off. And as Mariner drains the bathtub further we're seeing things there climbing towards the Belvieu price.
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 Marcus to Far East and Northwest Europe there's good demand and good world growth.
So, it sounds like you could also keep more volumes in Appalachia too just because pricing is improving there?
Yes. Yes that's right.
Got it. And maybe just a credit question for you. Obviously, the borrowing base redetermination is coming up in the spring. Could 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 million to 300 million. Curious if you're still comfortable with that number? And how maybe a surety bond market may offset some of that?
Yes on the borrowing base we'll have to see where the bank price decks come out. They'll be out in the next couple of weeks I think. And that 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 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 $1 billion-plus cushion above our lender commitments of $2.6 billion maybe it's $1.5 billion cushion somewhere in that range. But we'll see how that shakes out. So, the good news is we have the borrowing base will be 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...
Yes on the LCs, I think Gregg you should probably note that we reduced some 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 LCs to replace them a surety bond. So hopefully we'll have some update for you on that, at the end of the first quarter.
So the $730 million takes into account, all the …
That's correct.
…. I think you said, there was -- so you've got that, you can possibly reduce it more you think?
Right, correct.
And I'll hope back in a queue. Thank you for your time guys.
Yeah. Thanks, Gregg.
And our next question is from Holly Stewart from Scotia Howard Weil. You may proceed with your question.
Good morning, gentlemen.
Good morning.
Hi Holly.
Maybe just first, you guys have talked a lot about the asset sale program. Glen 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, in the A&D market. So we're not out there marketing, anything specifically in the A&D market. 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 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 going to 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, through the spending as well as the sort of production outline?
Yeah. The production is a ratable growth, Holly up to average at 3.5, from the Q4 2019, on the capital. The capital slightly a little more in the first and second quarter as we mentioned with those drilling efficiencies, in our drilling ability of those four rigs are currently running right now for the first three quarters.
And then its 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 a follow-up on the, LC question, so, it looked like at year-end you're at $623 million. And you're saying post the rating agency movement now you're at $730 million. And then you'll look to decrease that with further surety bond issuances?
Correct. That's correct yeah.
Okay. Great, thank you.
Thank you.
And our next question is from Arun Jayaram from JPMorgan. Please proceed with your question.
Yeah. Glen, I was wondering about your longer-term hedging strategy, looking beyond 2021.
Yeah. I'll let Paul comment on that.
Yeah. So we've made the point especially on gas, that we're hedged through 2021. So, we – obviously, we've 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 the price falling away like it has recently.
So, we're looking out there. But the prices are not interesting enough for us right now. But we'll -- 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 NGLs but we're pretty solid on oil for this year. And as you know, it's -- oil goes up and down but very liquid and very readily doable on a short notice. So we'll watch that as well from 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 if we do have some merchandise of the EQT does have a processed on the mineral side and perhaps your Utica asset. But can 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 of 2, 3 asset sales that kind of equated to at 12.5 times kind of multiple in terms of cash flow, as well as what you're seeing in terms of market appetite for undeveloped acreage or non-cash flowing acreage in Appalachia?
Yes. I'd just say, we have -- we see strong interest in all that and we won't have any color to announce on it until we have a deal to announce. So that's all, I'm going to say on that at this point.
Fair enough. Thanks a lot.
Thank you.
And our next question is from Betty Jiang from Credit Suisse. Please proceed with your question.
Thank you. Good morning. So just looking at the -- on the cost side, cash costs came down $0.07 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?
Yes 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 feel 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 AR of course as the spreads widen the third-party gas or as spreads widen and laying off any full paths and get prepaid, we could see improvement as it becomes more constrained. And as the spreads widened 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 follow-up just on that too, on 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. That of course on all pipes, the spreads get remarked every day or even within the day meaning 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 and as they have since the fourth quarter. And so sure there's definitely potential for that to help us.
Got it. Thank you for that.
[Operator Instructions] Our next question is from Tarek Hamid from JPMorgan. please proceed with your question.
Good morning.
Hi Tarek.
Good morning.
Just a follow-up on the LCs. Can you maybe just talk a little bit about 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?
Yes 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 then 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 it to a third party sort of what's the calculus in your mind between sort of control versus non-control on the buyer?
Yes. 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. So, they're not trading at an attractive price for a sale right now from AR's perspective, I don't think so. We'll see how that plays out over time Tarek, but it's something that we'll just keep an eye on. It's not sort of our number one priority right now.
And that was literally my follow-up on how do you think about the timing given that sort of 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 just -- I wouldn't hyperfocus on that. I mean 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 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 in queue. 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.
Yes. 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.