Thank you for joining us for Antero's Third 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 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. 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 will provide an update on the considerable progress we've already made on our well cost-savings initiative.

I will also discuss meaningful operating cost reductions that we have achieved across our business that we expect to further reduce going forward. Glen will then highlight our third quarter financial achievements and our expanded hedge position that now covers essentially 90% of our projected natural gas production through both Cal-20 and Cal-21.

He will conclude with comments on our balance sheet and liquidity position. I'd like to start by discussing the expansive cost savings efforts underway at Antero.

Over the last year, we have been intensely focused on reducing the overall cost structure at Antero to make us more competitive in a lower-for-longer commodity price environment. This process includes a line-by-line review of every expense item throughout the company.

Through this comprehensive review, we have identified the potential to remove $250 million from our overall cost structure in 2020 alone. As detailed on Slide 3 titled cost reduction strategy overview, the majority of these significant reductions will come from lower well costs and reduced LOE.

Firm transportation mitigation and G&A reductions account for the remaining savings. These efforts are already delivering results as our third quarter D&C CapEx was $290 million, the lowest quarterly spend since our IPO in 2013.

Further, due to the cost savings realized to date, we reduced our full year 2019, D&C CapEx budget to a range of $1.275 billion to $1.3 billion, a nearly $100 million reduction from the midpoint of our original 2019 guidance. Despite this capital reduction, we increased our annual production guidance to the high end of the prior range, a 2% increase at the midpoint.

Now let's discuss each of these items individually. Last quarter, we announced a well cost-savings initiative that targets 10% to 15% reduction in well costs on a per lateral foot basis or approximately $1.2 million to $1.7 million per well.

Turning to Slide 4 titled targeted Marcellus well cost reductions. We began with our January 2019 well costs at $970 per foot that was assumed in our budget.

Today, our all-in well costs are $895 per foot, which equates to savings of nearly $1 million per well. And by all in, I do mean all in as our well costs include pad, roads and facilities costs, which are, on average, $900,000 per well or $75 per foot.

The savings already achieved are substantially ahead of the second half 2019 target of $930 per foot that we announced last quarter. We were able to accelerate localized water blending operations during the third quarter, which reduced flowback water costs ahead of schedule.

Our team was able to quickly execute a development plan to blend flowback water at the pad sites being completed during the third quarter, which was ahead of our initial time frame. This acceleration illustrates the direct benefit of our relationship with Antero Midstream as compared to the long lead time that would have been required if we were working with a third-party midstream provider.

The closure of the Antero Clearwater facility also accelerated well cost savings as we increased blending in order to minimize the high wastewater injection fees and trucking costs associated with it. Also contributing to lower well costs was drier completions.

During the quarter, we used fewer barrels of freshwater per foot in approximately 20% of our completion stages. Looking ahead, we are targeting a well cost of $830 to $870 per foot in 2020 and have outlined several savings initiatives to achieve this goal, all of which are within our control.

By the first quarter of 2020, we anticipate an average well AFE of $880 per foot, with further declines expected as we move through the next year. Turning to Slide 5, titled Marcellus drilling and completion efficiencies.

We also continue to realize cycle time improvements. During the third quarter, we set new records for average lateral length -- average lateral feet drilled per day, averaging 6,000 feet per day and setting a new 1-well world record drilling 10,067 lateral feet in a day, in 24 hours.

This dramatic increase in lateral feet drilled per day has reduced the days to drill as well to 11 days from spud to spud. That's a 62% improvement since 2014 despite having increased our average lateral length by 42% to 11,500 feet.

Further, the reduction in freshwater used in our completions helps increase our completion stages per day, which increased to a new quarterly record of 5.9 stages per day and we also set a new record, a 1-day record of 11 stages in a day. Slide 6 titled Antero water savings performance, highlights the reduction in LOE and capital driven by our transition into blending and reuse of produced and flowback water.

We expect to increase our blended water for reuse to 40,000 barrels a day on average in the fourth quarter from 10,000 barrels a day on average in the third quarter. This increase in blending operations, combined with reduced trucking miles and lower negotiated trucking rates, is projected to result in over a $4.50 per barrel decrease in water-handling expenses compared to the first quarter of this year.

As shown in the green line on the chart, we expect this per barrel decrease will translate to approximately $57 million in cumulative 2019 savings relative to our initial budget. Slide 7 titled water savings driving LOE lower illustrates the overall LOE impact from the water-savings initiative.

Our third quarter LOE of $36 million was down 17% sequentially. Historically, produced water costs represent 80% of our LOE.

By transitioning our operations to localized blending and reuse starting in August and shifting away from the Antero Clearwater facility in September, as the facility was idled, we were able to drive down our LOE substantially. We expect even further reductions in LOE going forward as we benefit from a full period of these cost savings with fourth quarter absolute LOE expected to decline another 15% or nearly $5 million.

As it relates to our 2020 outlook, we anticipate LOE savings of at least $60 million from these initiatives compared to 2019. Our goal is to blend 100% of our flowback and produced water.

This is achievable, we believe, we have actually reused 100% a number of times, and set a new record just this last week of blending 60,000 barrels a day, so we believe it's quite possible. Turning to Slide 8 titled firm transportation mitigation and guidance update.

We continue to work aggressively at mitigating our excess firm transportation cost. We recently released 250 million cubic feet a day of excess FT to third parties during the months of September 2019 through March of 2020.

This offload will reduce our net marketing expense by $15 million over the next several months and led to the lowering of our 2019 net marketing expense guidance by $0.02 per Mcfe at the midpoint. We continue to see attractive opportunities to market some of our excess firm transportation capacity driven by the recent widening of local basis at attractive spreads to the Midwest and Gulf Coast.

As illustrated on the chart, 2019 is our peak year for firm transport capacity of 4.6 Bcf a day. At Antero's option, this capacity comes down by 100 to 200 million cubic feet per day, each year going forward declining to 4.1 Bcf a day in Cal-23.

We expect to have essentially all of our premium firm transport organically filled by the fourth quarter of 2021. Switching to G&A expenses.

We recently lost -- launched a cost-savings initiative targeting a 10% or $14 million annualized run rate reduction in mid-2020 -- by mid-2020. These savings will come through employee headcount reductions that occurred earlier this year, natural employee attrition and reduction across the board in business operating expenses.

In summary, we will remain steadfast in reducing our overall cost structure with a goal of being a peer leader in returns regardless of the commodity cycle. Our relentless effort to reduce costs has already delivered benefits as highlighted by 2019 capital guidance being reduced 4% to under $1.3 billion.

Despite reducing capital, we are increasing our production target to the high end of our initial guidance range of 3.15 to 3.25 Bcf equivalent per day, highlighting the improving capital efficiency of our assets. Looking ahead, with these lower costs, we now expect D&C CapEx to be under $1.2 billion in 2020 while delivering production growth in the range of 8% to 10%.

This preliminary target is supported by our peer-leading hedge positions with 90% of our natural gas protected through Cal-21 at prices well above the strip. Based on the current commodity strip, we expect our 2020 modest growth program to outspend by $100 million to $150 million.

Important to note that our capital program will remain flexible depending on NGL prices, and can be reduced accordingly in order to prioritize the strength of our balance sheet. With that, I will turn it over to Glen for his comments.

Thank you, Paul. Turning to Slide 9 titled industry-leading natural gas hedge position.

We continue to add to our hedge position during the third quarter and through October. The orange line on the graph represents our hedged or fixed price swap prices for natural gas.

We're now 91% hedged on natural gas in 2020. at an average price of $2.87 per MMBtu and 89% hedged in 2021 at an average price of $2.80 per MMBtu, assuming the midpoint of our 8% to 10% growth target in 2020 and 10% growth target in 2021.

It's important to note that we continue to offset our annual net marketing expense with hedge realizations. Based on strip pricing today, our hedge realizations will more than offset our net marketing expense through the year 2021.

It is notable that we remain the only publicly traded U.S. producer that is 100% hedged on expected natural gas production for the remainder of 2019, and have significantly more hedge protection in 2020 and 2021 than almost all of our Appalachian peers.

This is an important investment attribute in a bear market for gas. Turning to Slide 10 titled C3+ NGL hedges, we also have been actively adding NGL hedges and were able to take advantage of the global price spikes following the missile attack in Saudi Arabia in September.

We are currently 50% hedged on our expected C3+ NGL volumes for the fourth quarter and are now 28% hedged in 2020. We have hedged 93% of our expected pentane or C5 volumes in 2020 at $47.84 per barrel and over 60% in 2021 at $44.94 per barrel.

The C5 volumes were first hedged at a percent of WTI, then the WTI price was locked with a fixed price oil swap, resulting in a fixed price for our C5 volumes. So our combined C5+ oil production volume is estimated to be 27,000 barrels a day for the fourth quarter of 2019 and closer to 30,000 barrels a day for 2020.

These volumes really represent our WTI oil exposure going forward, and we have hedged 85% and 50% of that volume for the fourth quarter of 2019 and 2020, respectively. We will continue to work toward managing our NGL price exposure by adding hedges across our domestic European and Asian markets.

Third quarter C3+ NGL price realizations averaged only $22.53 per barrel. Although there was a seasonal NGL price decline from the second quarter, we were once again able to realize a premium to Mont Belvieu prices due to our industry-leading exposure to the international LPG market through our capacity on ME2, Mariner East 2.

As illustrated in the bottom-left table on Slide 11 titled NGL transportation delivering premium pricing, we shipped 54% of total C3+ net volume on Mariner East 2 for export in the third quarter and realized a $0.12 per gallon premium to Mont Belvieu at Marcus Hook. The remaining 46% of C3+ net volume was sold domestically at $0.13 per gallon discount to Mont Belvieu pricing at Hopedale.

This resulted in a blended price, which was a $0.01 per gallon premium to Mont Belvieu pricing. In the table on the right-hand side of the slide, we provide guidance on NGL realizations relative to Mont Belvieu pricing for the full year of 2019.

Looking forward, we see the third quarter as the trough in NGL prices. This is supported by the recent price strengthening seen since early October as depicted in the chart on Slide 12 titled NGL price improvement.

Based on current strip prices, we anticipate a $5 per barrel improvement in realized C3+ NGL prices in the fourth quarter of 2019. The improved pricing has been due to a combination of factors, including seasonal effects as we transition into winter, increased dock export capacity on the Gulf Coast, ongoing global supply disruptions following the incident in Saudi Arabia and continued robust international LPG demand.

It's important to note our leverage to NGL prices as the second-largest NGL producer in the U.S. For 2020, for example, a $5 per barrel improvement in the roughly $25 per barrel C3+ strip price, that we're using in our estimates, would generate an estimated $170 million of additional cash flow, thereby eliminating our estimated $100 million to $150 million outspend in 2020.

As we highlighted during the second quarter call, heading into 2020, we see fundamental tailwinds to NGL prices driven by additional export expansion capacity projects along the Gulf Coast and East Coast at Marcus Hook that will provide relief to stranded supply and support domestic prices. On the international front, new PDH plants in China, combined with incremental import capacity across India and Europe, are expected to drive continued strong demand in the international markets.

Moving on to Slide 13 titled strong financial position for low price environment. Maintaining a strong balance sheet remains the top priority at Antero.

Our current balance sheet strength positions us well to weather any sustained downturn in the market. We have reduced absolute debt by approximately $700 million over the past few years, resulting in a mid-2x leverage today.

We have $1.2 billion of value in our AM ownership that provides over $200 million per year of steady cash flow in the form of dividends, and our hedge mark-to-market value is currently $807 million. Our borrowing base was reaffirmed at $4.5 billion during the spring redetermination.

This October, we added RBC to our lending group with a $140 million lender commitment, increasing our total bank commitments to $2.64 billion. We currently have only $275 million drawn on the facility and $700 million of letters of credit.

So today, we have almost $1.7 billion of committed liquidity under our credit facility, plus almost $1.9 billion of uncommitted first-lien capacity. While we have no plans to utilize the additional first-lien capacity, the combined $3.5 billion of first-lien borrowing capacity services as a backstop that would enable Antero to repay both its 2021 and 2022 bond maturities with new first-lien commitments if the unsecured market doesn't materially improve.

And this backstop is supported by 10 Tcfe of PDP reserves, the dividend stream from AM and almost $1 billion of hedge value, and that's at bank pricing. Other liquidity options include asset sales and further cost reductions.

Some of the asset sale alternatives are hedge monetizations, which we've done in past; the sale of AM shares, which we did in the simplification earlier this year; and land sales, which we have done in the past. Also recall that we have 84% average NRIs in the Marcellus and the sale of overriding royalty has been demonstrated to be a viable asset in monetization strategy.

We don't rank that as an attractive alternative for us as our net interest and production is core to NGL. Additionally, further cost reductions will strengthen AR's cash flow and borrowing base capacity above the estimates provided above.

At the time of our spring redetermination, we had not yet announced our well cost-savings initiative, LOE reduction or G&A cuts. The continued execution on these important initiatives will support our borrowing base capacity next spring.

Any reduction in GP&T costs could materially enhance the cost-reduction initiatives. The key takeaway is we have abundant refinancing and liquidity alternatives available to navigate a lower-for-longer commodity price environment.

For an integrated natural gas and liquids producer with the scale that Antero enjoys, there's a spectrum of alternatives available, it's not a binary situation. Importantly, we can be patient as our cost-reduction initiatives play out, and believe that the bond market will offer attractive refinancing rates to solid upstream credits over the next year, particularly with cyclical commodity price improvement.

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

You guys have obviously taken advantage of the recent dips and volatility at Dom South and M2. Can you talk to how you see those 2 hubs developing going forward?

And I guess through year ending in '20, is that volatility something you see as transient? Or do you think it will continue through year-end '20?

I think it will continue probably through year-end '20. There's still some constraint in the regional pipeline systems, that being, for example, the Tetco shutdown with a resumption.

It will probably resume at a lower takeaway capacity, but we just see things are a little bit constrained there in the Dom South, Tetco M2 market. I think when the spreads widen to Chicago then the distressed gas gets bought up at a premium to M2 or Dom South because there are a number of shippers, including ourselves, that buy the distressed gas and move it.

So it goes up and down, it's volatile due to the physical constraints and then when spreads widen then it gets bought up and then when spreads are not -- don't justify the variables then it languishes again. So we think until there is more pipe built out of that Northeast area that it's going to go up and down depending on weather and pipeline capacity as it comes online or doesn't.

Okay. And in that type of environment, is it fair to assume that you guys would be able to get some more release capacity agreements.

Do you think there's depth to those type of deals?

Yes. Yes, we do.

So we've demonstrated we're perfectly willing to release some capacity to other parties and the spreads justify that and -- or we can buy the distressed third-party gas and collect the margin. So we are constantly looking at both of those options.

Okay. And then just one last one for me.

I suppose it's less applicable to you all, but there's been some chatter about pipelines demanding extra letters of credit that can be triggered by 1 thing or another, is that something that could potentially manifest in '19 or in '20? And what would the trigger points that maybe we should pay attention to be for that?

Yes. We've looked through all of our agreements.

When we look at all of our FT agreements, there's about 3 of them that have provisions that if we get the downgrades, there would be an increase in the letters of credit. The downgrades are actually -- they actually tie to what our ratings were at the time of the agreement.

So it's back to 2014 when we were rated a couple of notch below where we're at. So right now, that would not affect us.

But if you do have further downgrades in the future, there could be a little bit of LC increases. Like we mentioned, right now, there's about $700 million of LCs, the order of magnitude of those increases are about $100 million to $300 million, but it would have to be a couple of notch downgrade from here.

We saw a significant pickup in the weighting towards NGLs as a percent of the total production mix this quarter, can you break out where and why you saw this and how you see that evolving through 2020 next year? Do you see a different range of liquids growth versus the 8% to 10% total growth guidance?

Well, we focused on highly liquids-rich locations from 1,250 to 1,300 Btu. So you're just seeing that incremental increase in the proportion of liquids.

And I'd say we expect it to be fairly steady in that range over the next year, Brian.

Great. And then my follow-up is, you highlighted multiple cost-reduction initiatives, reductions in marketing expense, and you added strip -- you're still outspending or expect to outspend cash flow modestly after some of the one-off benefits, does your $100 million to $150 million of outspend assume the full impact of the cost-savings initiatives discussed today?

And beyond the commodity price improvements, what do you see as the drivers of upside to the free cash flow range?

Yes. That forecast does include the LOE improvements, the well cost improvements, that's all baked in.

And hopefully, those numbers are conservative, and we'll even do better than those numbers. But we also mentioned -- or I mentioned in my comments, just that there are other cost initiatives underway outside of that on the midstream transport side.

So we're having a number of discussions there. So you could see some improvement there over time and that could be material as well.

And I guess with regards to the conservatism bake in, if there is an area of focus where you think there's a more significant opportunity for cost reduction of the multiple initiatives you talked about, would you point that more towards the well costs, the LOE or the midstream side?

Yes, I would say both well cost and LOE. I think on the well cost side, we feel pretty good about getting below $800 per foot there.

And so hopefully, we'll outperform on that. And -- but the GP&T cost, that's all a negotiation that takes place over time.

We've mentioned that on previous calls. There's no guarantee that any of it gets done, but some of it does, it could be pretty material.

Yes. Sorry, guys, Subash here.

The -- I guess the first question -- first of all, congrats on a very eventful quarter so I'll try to get a few of these in. The GP&T or I should say the cash production expense outlook for 2020, what is that range now?

Yes. We haven't put out a range there, but it's similar to this third quarter.

I think it's between $215 million to $225 million.

Okay. And on the water side, how much more can you press that with regards to -- it looks like 100% recycling was sort of somewhat isolated maybe, it could be a lot more broadly applied than that.

And the 10 goes to 40. So what could be a pie in the sky number eventually on the water handling?

Well, I think certainly within our site, Subash, we could see -- it takes planning and so on, but as much as 100% blending of all of our flowback and produced water. And so as our production grows, I think steady state right now, roughly steady state with 3 frac crews, 45,000 barrels a day.

With 4 crews that we're operating right now, the flow back can produce 60,000 barrels a day. And our teams are handling that quite well.

We just keep getting better at it. So I do think that's achievable that as we go forward, we have a bigger production base, there'll be a little more produced water.

And varying between 3 and 4 frac spreads, we'll be in that 50,000 to 60,000 barrels of produced flowback. And I think that's all achievable, and it's going to be -- our old LOE was above $10, including Clearwater, $10 a barrel, and we're getting it down into the mid-$4s now.

So there could be quite a bit of savings, certainly, above the $50 million a year. So feel optimistic about that.

Our Utica volumes are pretty low. They are about 4,000 barrels a day.

Right now, we take that to injection, and it's pretty, pretty low cost, it's under $4.50 a barrel between injection and trucking since it's near the injection site. So anyway, we do think that LOE and as we've said in our press release or in our remarks, water is about 80% of our LOE.

So as we make big strides on the water side, we can really reduce that LOE.

Okay. And final one on back to the LC discussion.

Are there alternative markets to kind of put the money out there away from the credit facility? It seems like offshore producers with FERC-regulated -- explosive FERC-related pipe seem to be able to do that in alternate markets.

Yes. Subash, that's a good point.

We are looking into that. There's -- the surety bond market out there is something we are exploring in order to satisfy some of those LC requirements.

So that could definitely offset any LC increases if we do get downgrades.

Got you. So you wouldn't -- you'd do it on the incremental amount, on the current amount?

Is that a...

We could do that or we could actually replace some of our existing LCs with surety bonds as well.

My first question is on production strength that we have seen year-to-date. Maybe you could provide some color on what has driven production outperformance.

Well, we've seen great well performance all year. And so that's really what it comes down to, just beating.

And part of it is getting those wells on sooner than expected. So we certainly schedule everything out for the year in our budget.

And when we beat that budget from a timing standpoint, the production comes on sooner and drives the quarterly production up higher. So it's a combination of those 2, well performance and timing.

Got it. My second question is on oilfield services.

So you kind of highlighted well cost savings, which mostly are driven by self-help initiatives. I'm just curious like how much of well cost savings are related to vendor-related cost reductions.

And maybe you can just provide general comments on oilfield service deflation, if any, in Appalachia.

Yes. There's definitely cost deflation with our vendors, and we've been working with them for a number of months now.

We've made requests and contacted, and there are several hundred vendors that we are involved with, but contacted them all and asked for a certain discount. And virtually, all have been willing to give that to us.

And then we've asked for extensions through the next year, and many have rallied forth. And so we feel that all our interests are in the same boat.

And so they definitely want to continue to work with us. We're very active.

And so they've been willing to cut. And so we feel good about that sticking for the foreseeable future.

Okay, got it. And then you guys provided this well cost guidance for 2020, does it include any well cost savings related to those vendor-related cost reductions?

No, those are already baked in. We've realized about $400,000 per well in savings in that arena and that's all that's baked in there right now.

So any further reductions would take those numbers lower.

You guys laid out an improved '20 program in terms of capital efficiency and you also look at lateral length that's above 12,000 feet on average now. I guess how -- it's been a while, I think, since you addressed like a very long-term program, where do you see lateral length progressing beyond '20?

And how can you match that up with some of the projected land spends that you have? I saw the $50 million in '20.

I think you guys have talked about kind of discretionary land spend before to get to the right working interest in lateral length over the next several years. How do you see that progressing beyond '20 to remain efficient on that basis?

We do see continued lengthening of the laterals over time. And I think we sort of get up into the 12,500 range over the next several years.

Of course, there'll be a range of lengths there. There'll be 8,000- and 9,000-foot laterals, but there will also be 15,000-, 16,000-foot laterals.

But the average is kind of -- are in the 12,500 range at the peak over the next few years through 2023. And we already have a lot of that land in place.

We have a very consolidated land position. So we already have very high working interest, and we feel like that $50 million sort of neighborhood gets us what we need in terms of any add-ons to keep very high working interest in our drilling.

Okay, fair enough. Also, just curious, the Utica impairment, I know not a whole lot of development there.

Can you talk about just how you think about that asset now with portfolio management? Is it something that's held and you'd hold on to for a while?

And can it become a source of funds? Just how would you square that now?

Yes. Of course, this was just an accounting adjustment, so it doesn't change our mindset strategically on the asset but it does have tremendous option value.

There's some great gas -- dry gas locations over there and some up-dip liquids-rich locations. It's just, at this point in time, in a very low price environment, it makes sense to keep your costs optimally low, of course.

And when you drill in the same area, you're able to use all the flowback water in your new next completion. So it just makes sense to keep the rigs in the Marcellus for now, but the Utica, those are important locations that are in our inventory.

And if you could just close out with one more. Just -- you saw some effort on the share buyback side this quarter.

Obviously, they are still projected at spend going on. You have increased, I guess, your lender commitments by welcoming RBC.

Some of your corporate bonds obviously trade at a discount. I guess how do you think about now one perhaps leaning on the revolver, I guess, to either buy back some debt or shares?

And I guess, what are the conditions that cause you all to look at the share buyback as a good use of funds?

We want to remain flexible on that. We were opportunistic here in the last quarter and picked up a few shares.

I think you'll see us do that some over time, but it's not going to be a heavy program until we see better commodity prices and stronger cash flow. So we want to preserve the balance sheet, primarily.

We certainly have the option to buy back bonds, and you may see us do some of that over time as well. We've got plenty of liquidity for that.

So we'll be opportunistic, I think, is the bottom line.

Okay. So is -- the share buyback now, is it just intended to offset sort of the natural dilution from employee programs?

No. No, it's just an opportunistic buy-in of shares, and it's a very economic thing to do at these kind of price levels.

The time -- on the comments on the balance sheet, just looking at your maturities, 21s and 22s, be interested in how you think about addressing those, do you need to come up with a solution for addressing them together? Or perhaps be more patient?

I think some of your comments suggested if the market remains challenging, you potentially addressed the 21s before then turning your attention to the 22s, so I'd be interested in any thoughts on that. And what makes you decide between secured and debt sooner or waiting for the unsecured markets to open up?

Well, the good news is we can afford to be patient. We have a lot of time.

So you really haven't seen the bond market shut down for even E&P for more than a few quarters. So we don't think this will last for a year, let's say.

But we can afford to be patient on it. And we look at both of those maturities, for sure, not as a bundle, but we look at both of them.

And whether we're on the secured market or not, that kind of just depends on how things play out over time. So it's a very fluid dynamic situation when you get into these kind of market dislocations, and you just have to stay on top of it, be aware and be ready to execute if there's something attractive.

That makes sense. Then when you think about kind of the market window required to allow you to keep that flexibility?

Is it 12 months, maybe it's nothing fixed like that. But when the bank start taking a look more -- a closer look at your maturities, it tends to be about 12 months.

Is that the right way to think about it, that basically, you have the whole 2020 to make a move and clarify your part? Or you maybe have less or more time, I'd be interested in anything on that.

Yes. I think that's a good way to think about it.

I mean you'd like to stay out of going current on your balance sheet. So that's the way to think about the 2021 anyway, that's right.

I guess on the kind of small FT monetization that you're doing over the winter, I guess could you share what the kind of end market is that, that pipe is going to? And I guess it looked like the kind of implied charge there is kind of roughly $0.30.

Just curious how we should be kind of thinking about that. Was that just a function of kind of tougher in-basin dips that kind of drove that decision?

Or any kind of commentary around opportunities beyond this winter?

Yes. Sean, we're looking at those all the time.

And the choice is whether to do an AMA, asset management agreement, and lease something out in a sense for an extended period, like we did here 6 or 7 months to go from the M2 pool over to Chicago or to manage it ourselves and buy and sell distressed third-party gas, moving it in that direction. And so that's right, roughly $0.30.

And so we -- and there's a pretty good market out there for release capacity. And so others saw the spreads and saw them in the forwards that they could lock in.

And so we made the decision to let go of those in mass. And so the flow path would be Rex Westbound out of Clarington and it connects with a couple of pipes that we have, MGT and NGPL over in Eastern Illinois, Scottland and Moultrie, Illinois into the Chicago market.

So they're generally into the Chicago City gate. And so good spreads.

And so those parties are working that. And the spreads have been positive quite a bit lately with this cold weather, so I think they're doing well.

And so that's what we look at all the time. And so those emerge quite often.

We're looking at spreads and whether we want to sublet as it were for some period or use it ourselves for our own gas for the very best realizations or buy and sell gas on the day and make up the -- some of the marketing expense that way. So have our choices.

Got it. That makes sense.

And then I guess as you think about kind of the maintenance versus kind of filling FT cases, I guess could you talk a little bit more about how you're thinking about that. And I guess specifically, since it would look like the market has been wanting producers to kind of go more to a maintenance case, how do you think about slowing down.

And I guess along with that, is there any ability to renegotiate with AM, just on the rate side to kind of improve cost of capital for both sides?

Yes. As we said, all of that's on the table, the whole GP&T expense line item.

So we're talking to everyone on that, at least all the material players. So we -- on the path forward, we kind of laid that out.

I think it was August 3, the last quarterly release, there's a roadmap in that deck where we kind of painted the picture of without any changes in firm transport cost and portfolio, it made sense for us to continue to modestly grow at this 8% to 10% over the next couple of years to fill up the firm transfer. Well, that's still the case.

So nothing's changed there, and that's the path that we're on. We'll see where these negotiations take us and does it reshape the FT portfolio enough to where it makes sense to slow a bit or take a more gradual growth profile if commodity prices don't change.

The good news is there are tailwinds on commodity prices right now, things are looking better and we have a lot of leverage to that, as I mentioned earlier. For every $5 change in NGLs, we pick up $170 million of cash flow next year, 2020.

In 2021, that goes to $250 million and up from there. So lots of leverage to these price changes.

And that's important to know. There's never a static kind of situation here.

Got it. That's helpful.

And then just lastly for me. And Glen, I know you highlighted on Slide 15, you're kind of just shy of $2 billion of uncommitted first-lien capacity.

I guess should we be thinking about that as kind of your remaining first-lien capacity, assuming kind of the borrowing base stays as it is? Or do you think there's kind of more beyond that?

Well, I think the first-lien capacity, that's -- we're just forecasting what it would look like off of the current $4.5 billion borrowing base. There could be a little bit of downside to that borrowing base, depending on where the markets are, where the banks are in the second quarter next year when we redetermine, but there's also a lot of upside with these cost reductions.

So the more cost reductions that we come up with, that enhances the borrowing base to the positive side. So I think that $4.5 billion is a good number to work with.

And that's first lien. And of course, beyond that, there's always additional asset borrowing capacity, whether it's second lien or whatever you want to call it.

So there is quite a bit of capacity in a company like this with 3.3 Bcfe a day of production and the liquids exposure and all that, the scale. So a lot of borrowing capacity there.

That's why we're being patient about the bond market and the healing therein, hopefully.

Got it. So the calculus you're doing on Slide 13, it's not necessarily kind of mirroring what is for maybe on the bond indentures, which is kind of off the $4.5 billion borrowing base?

Correct.

So can you elaborate on the opportunities that you're currently pursuing to potentially reduce the GP&T cost? There are certainly many counterparties in that line, so just trying to understand whether the conversation is with AM or other entities.

And are we talking about amend and extend agreement or something different?

Yes, it's all of that. And all of those parties, as I mentioned a minute ago, it's every party that we do business with, both on the service provider side and then also on the midstream transport processing side, all of that.

So we're having those discussions with all parties, they're partners in the business, overall. So we think that we will make some progress there and having some pretty healthy discussions on that.

So that is a key focus, but I can't elaborate on any particulars there. But amend and extend is a good way to think about it.

What type of magnitude are we thinking about here? Like is it sort of pennies, nickels any sense that you can provide?

No, but it could be material. I'd say $0.01 is not material.

So larger than that.

Okay. And then my follow-up is just on you've been -- Antero has been put on negative watch by several rating agencies.

So in your conversation with them, what are they looking for from the company to avoid the potential credit downgrade? And just want -- trying to understand does their thought process get influenced by how Antero plans to address the 2021 and '22 maturities?

Yes. So once again, it's all of that, Betty.

It's how are you going to address 2021 maturities, and are you going to do anything on the asset sale side or for the cost reduction side or there's also the hedging side, we've made quite a bit of progress there recently, which really locks down prices and your future cash flows. So it's all of those topics that get discussed in the market today.

Thank you for joining us for today's conference call. If you have any further questions, please feel free to contact us.

Thanks again.