Antero Resources Corporation (AR) Q2 2019 Earnings Report, Transcript and Summary

Greetings, and welcome to the Antero Resources Second Quarter 2019 Earnings Call. At this time, all participants are in a listen only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host Mr. Michael Kennedy, Senior Vice President of Finance. Thank you. You may begin.

Thank you for joining us for Antero's second 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 new 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 like to first 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.

Thanks Mike. Thank you to everyone for listening to the call today. In my comments, I'm going to spend some time talking about our long-term strategy and focus on I recently announced well cost and operating cost savings initiatives. I'll provide detail on savings we've achieved today and highlight the key items that will reduce costs further towards our target. Glen will then highlight our second quarter financial achievements including the premium NGL price realizations following our first full quarter with Mariner East 2 in service. He will conclude by discussing our expanded hedge position through 2022 and our capital spending outlook. I'd like to start by discussing our long-term strategy. We remain focused on maximizing our ability to generate free cash flow on a sustained basis. As we look at our five year development plan today, the best way to deliver maximum free cash flow on a sustainable basis is to grow production in the near term to fill our firm transportation commitments while we have attractive natural gas hedges in place. At current commodity strip prices, we forecast funding this growth primarily through cash flow from operations and the water earn out payment of $125 million expected in Cal '20. This allows us to preserve our strong balance sheet. Once we grow into our firm transport and essentially eliminate net marketing expense in 2022. We're well positioned to be more flexible with our development plans and generate significant free cash flow. To provide some context, if we elect to just maintain yearend 2021 forecast production approximately 4 Bcf equivalent per day, the capital required to do so would be less than $900 million. This would result in our ability to generate free cash flow of over $400 million in Cal '22 even at today's commodity strip prices or over a 30% free cash flow yield. As opposed to downshifting to maintenance CapEx today and delivering one year of free cash flow with unfilled pipeline commitments remaining, our strategy positions us to deliver long-term sustained free cash flow generation. Now let's turn to our well cost savings initiatives. Regardless of commodity price cycles, we remain committed to maximizing value. Over the last several quarters, we undertook an internal review of every expense associated with our well cost with the goal of materially reducing costs to maximize returns. Let's turn to slide number three titled Targeted Marcellus Well Cost Reductions. Please note that all these numbers assume a lateral length of 12,000 feet. We are targeting a reduction in well costs of 10% to 14% on a per lateral foot basis or approximately $1.2 million to $1.7 million per well by 2020 compared to our 2019 budgeted costs. On a $1 per foot basis this translates into a reduction from 2019 budgeted costs of $0.97 million per 1000 feet to a target of $0.83 million to $0.87 million per 1000 feet. This is expected to be reached by the beginning of Cal '20. These savings have come or will come from a combination of water savings initiatives, service cost deflation and continued efficiency gains. Meeting our target will position us at the low end of the cost curve among our Appalachian peer group. Now let's take a step back and talk about what we've already achieved today. Following the waterfall on the page, we begin with our January 19 well cost at $0.97 million per 1000 feet that was assumed in our budget. Through the first half of the year, we've already achieved savings of approximately $500,000 per well, which brings us to our current AFE, with second half 2019 well costs estimated at $0.93 million per 1000 feet. This progress was the driver behind lowering our 2019 CapEx guidance back in May, without any change to our planned activity. We're very proud of our team's ability to deliver on this target significantly ahead of schedule. This achievement reflects both continued operational efficiency gains and service costs deflation that was realized during the first half of 2019. From our current AFE of $0.93 million per 1000 feet lateral, we expect well cost to decline further to the range of $0.83 million to $0.87 million per 1000 feet by Cal '20. These additional savings are expected to come primarily from our water savings initiatives, both on enhanced flow back water management and completion optimization. Now let's take a closer look at our major components of our well cost savings. We talked about the timing of well cost savings, but I wanted to provide a breakdown of the magnitude of each category. On slide number four titled Cost Reduction Initiatives Breakdown. You can see the breakdown by category assuming the midpoint of our targeted well cost reductions of $1.2 million to $1.7 million. We are targeting approximately $800,000 per well in well cost reductions for more efficient flow back and produced water management, as well as optimized completion design. On the flow back and produced water side we expect to reduce costs through a combination of first, polishing and blending the water to reuse in completions; secondly, repurposing portions of our existing freshwater system to transport the water and three, constructing additional water pipeline infrastructure. Historically, we've used third party trucking companies to transport our flow back and produced water at a cost of between $6 and $9 per barrel. Over the last 12 months, we have paid nearly $160 million to third party trucking companies. This situation provides Antero with a significant opportunity for improvement and for material savings on a per barrel basis, while also expanding the scope of the flow back and produced water services business for Antero Midstream. On the water used for completions, earlier this year, we began performing pilots across our acreage to test and analyze the optimal completion design to maximize returns. After successful pilots using mostly 100 mesh proppant, we now plan to reduce water used in completions from a range of 40 to 45 barrels per foot down to 35 to 38 barrels per foot in a new cost efficient completion design. The completion design optimizes both fracture lengths driven by water usage and reservoir conductivity, which is driven by the type and amount of proppant in the most cost effective manner. We've not seen any evidence of degradation in either production or EURs in all of our piloting and we do not expect it going forward. The second component of our well cost savings initiative is service cost deflation and efficiency gains. And often overlooked byproduct of lower commodity prices and reduced industry activity is a deflationary service cost environment, service costs go down. This is especially true in the Appalachian basin, where producers have lowered capital programs while also continuing to realize efficiency improvements. Given that Antero has remained one of the more resilient producers in the basin through all cycles, we've maintained excellent relationships with our vendors. In early 2019, we began working with our vendor partners to find areas to reduce expenses. The result of these extensive conversations was a meaningful reduction in total vendor costs. Further savings will come from last mile sand sourcing logistics and additional sand contract it was recently finalized with a premier sand supplier. On the efficiency gains, as we have highlighted during many of our earnings calls, our team's operational efficiency gains continue to surpass expectations. Slide number five titled Marcellus Drilling and Completion Efficiencies, highlights the many advancements that we achieved during the second quarter of 2019. During the quarter we averaged 5470 feet of lateral drilled per day, that's approximately one mile, little over a mile every single day, 20% improvement from our 2018 average. In addition, we achieved what we believe is a world record again, by drilling a total of 9650 feet of lateral in one day, which we're extremely proud of. Completion stages per day averaged 5.7 stages per day and increased from the 5.2 stages per day average in 2018. We continue to drill longer laterals. During the quarter we were able to drill our longest Marcellus lateral ever at 16,279 feet sideways. These efficiency gains combined with service cost deflation, are expected to reduce well costs by approximately $650,000 per well, assuming the midpoint of the target range. The enhanced produced water management will also reduce lease operating expenses. Let me clarify how we talked about water in terms of well cost and LOE. When we complete a well after perforating and stimulating it, we flow the well back and begin to recover the water as we turn it in line. We categorize the first 90 days as flow back water and the cost to track and recycle it is capitalized as part of the well cost. After 90 days we account for the well, the water as produced water and the cost to track and recycle it is considered LOE. So let me talk a little bit more about LOE lease operating expenses. In the first half of 2019 produced water costs represented approximately 80% of total LOE. Assuming Antero Midstream provides the new expanded produced water services, we expect LOE to be reduced by at least 20% in Cal '20 compared to Cal '19 budget costs. This equates to savings of at least $50 million on an annualized basis. Slide number six titled Appalachian Peer Marcellus Well Cost Comparison, provides a snapshot of our Appalachian peer well cost and future targets. Keep in mind that there is a variance among producers as to what costs are captured in capitalized well cost versus LOE, but the trends are useful. As you can see, our new well cost target will move us from an average ranking to becoming one of the lowest cost producers in the lowest cost natural gas basin in the world. While we recognize that some of these costs initiatives have not been fully realized today, we're already seeing results from the company's focus on costs, as we achieved the lowest capital spending quarter in our history at $303 million for the quarter. Over the last 12 months our drilling and completion CapEx was $1.55 billion, which delivered 700 million cubic feet equivalent of production growth. This was accomplished while standing near cash flow levels highlighting the attractive capital efficiency of our asset base. Going forward, we anticipate a quarterly D&C CapEx run rate approximately in line with the second quarter spend in the $300 million to $325 million range. In summary, we will continue to prioritize maximizing value through an intense focus on costs. The reduction in well cost is expected to deliver 2019 drilling and completion capital at the low end of our guidance range and lead to a lower D&C capital target of $1.2 billion to $1.3 billion in Cal '20. The decline in capital spend during Cal '20 is despite a similar number of well completions to 2019, but actually with a 19% increase in total lateral footage completed next year due to longer laterals. With that, I'm going to turn it over to Glen for his comments.

Thank you, Paul. The second quarter was the first full reporting period with Mariner East 2 pipeline in service giving us access to premium price to global LPG prices our markets. We hold about one third of the current 165,000 barrels a day of capacity on Mariner East 2, making us the largest shipper on this pipeline. During the quarter we realized an unhedged average C3+ NGL price of $28.57 per barrel for the quarter. That's a $1.68 per barrel premium to Mont Belvieu pricing, as shown a slide number seven titled Inflexion Point in NGL Marketing and Pricing. 55% of C3+ volumes were exported and realized a $0.19 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 2019. As you can see on a blended basis, it's essentially flat to Belvieu to a slightly positive premium of $0.04 per gallon. Now let's take a look at the impact of that ME 2 has had on northeast NGL differentials. Since the in service of ME 2 in February of this year, Antero's NGL price differentials improved by over $6 per barrel, flipping from a discount to a premium to Mont Belvieu. This improvement is not only from our sales in the international market, but also from the strengthening of in basin pricing in the northeast. The approximately 165,000 barrels a day flowing on ME 2 evacuates almost 40% of the basin's NGL supply. On slide number eight titled Improvement in Northeast NGL Differentials. You can see the significant improvement in price realizations following the startup of ME 2. ME 2 is that dotted vertical line over to the right. First half 2018 realizations averaged at an approximate $5.75 per barrel discount to Mont Belvieu. Despite the softer domestic prices seen during the first half of 2019 versus the prior year, our realized price relative to Mont Belvieu improved by over $6 per barrel and flipped to a premium to the index. In addition, and although not depicted on this chart, our in basin C3+ NGL price realizations have also improved following the startup of ME 2. C3+ NGL realizations over the past four years have averaged about $7 per barrel, you can see that on the orange line their discount to Belvieu, but have improved by 30% in the first half of 2019. Looking forward to 2020 with the completion of the full ME 2 project expected by the end of 2019, total pipeline capacity will increase to 275,000 barrels a day on ME 2. At that time, we have the option to increase our capacity by as much as 50,000 barrels a day and 10,000 barrel increments that would take us up to 100,000 barrels a day of firm capacity, which would increase our exposure to international pricing to the 65% to 75% range on Antero's expected NGL production in the year 2020. This expansion would also evacuate a higher percentage of regional supply, which is expected to further boost in basin price differentials. Our significant volumes on ME 2 give us the highest exposure to international LPG markets, which positions us to deliver peer leading NGL price realizations going forward. For those of you who have missed it, we have been publishing a new presentation on our website titled Weekly International LPG Pricing Update on the homepage, which provides a summary of benchmark international commodity prices for propane and butane. We hope this helps to provide better visibility on the 50% of our NGL volumes that we sell into international markets. In short, the propane and butane futures curve is in contango over the next couple of years. And the northwest oil prices are at $0.08 and $0.14 per gallon premium respectively to Mont Belvieu net of shipping. I'd like to touch on the NGL macro briefly, the current week NGL pricing in Mont Belvieu is due to limited export capacity along the Gulf Coast. Although we expect soft prices to persist through the third quarter, we do see Mont Belvieu fundamental strengthening during the fourth quarter and into 2020. The completion of export expansion projects along the Gulf Coast are expected to come online by the fourth quarter of this year, providing relief to the stranded supply that is negatively impacted Mont Belvieu NGL pricing. In the Northeast, the in service of full capacity on Mariner East 2 will provide increased exports through the terminal. We expect these projects to provide upside to domestic prices as well. We also see strengthening of international prices is up to six new PDH plants are expected to be placed in service in China by yearend this year, while Europe and India are also expected to complete additional imports terminals. In summary, we expect NGL pricing to improve as we see fundamental strengthening in the country quarters. Turning to slide number nine titled Peer Leading Hedge Protection. During the second quarter we added to our 202 and our 2021 natural gas hedge positions. We are now approximately 90% hedged in 2020 at an average price of $2.87 per MMBtu and over 35% hedged in 2021 at an average price of $2.88 per MMBtu, assuming approximate 10% annual production growth this year. 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 2021, as you can see depicted on slide number 10. It's notable that we remain the only publicly traded US producer that is 100% hedged on expected natural gas production in 2019 as shown on slide numbers 11 and 12. Have significantly more hedge protection in 2020 and 2021 than most of our Appalachian peers. This is an important investment attribute in a bear market for gas. Moving on to slide number 13 titled Strong Financial Position for Low Price Environment. Our balance sheet is in the strongest position in our company's history. We have reduced absolute debt by over $700 million over the last few years, resulting in low two times leverage. We have 1.4 billion of value in our AM ownership that provides us over $200 million per year of steady cash flow. Our borrowing base was reaffirmed at $4.5 billion during the spring redetermination that was an April with unchanged commitments at $2.5 billion and only 175 million drawn on the facility. We have over $1.6 billion of liquidity available. This highlights the strength of our asset base and the depth and resilience of our drilling inventory. Before turning the call over to questions, I would like to comment further on our well cost reductions and capital outlook as we look ahead. As Paul mentioned, the $303 million of CapEx was a quarterly low for us. However, the new well cost savings initiative underway, we expect to deliver quarterly CapEx in the low $300 million to $325 million range through 2020, assuming the current commodity strip. On an annualized basis, this results in CapEx in the range of $1.2 billion to $1.3 billion in 2020. The reduced well cost combined with our strong hedge position over the next several years support measured production growth while spending near cash flow levels. As a reminder in 2020, we anticipate receiving the $125 million water earn out payment from Antero Midstream and approximately $150 million for the natural gas pricing litigation, providing further support to our balance sheet. Our focus remains on maintaining a strong balance sheet. We have the flexibility and the strong asset base to adjust our development plan depending on the commodity price environment. Lower well cost lead to a reduction on our maintenance CapEx estimates. Turning to slide number 14 titled Maintenance and Decline Rate Projections. We now project maintenance CapEx that's a key production flat at 3.2 Bcf a day to be approximately $70 million. In summary, please turn to slide number 15 titled AR Has Built a Resilient Business Model. Despite the macro and market headwinds today, we built a business that is resilient through all environments. We've achieved significant scale and product diversity while maintaining balance sheet strength. Our peer leading hedge book and midstream ownership provides substantial liquidity and affords us protection through sustained downturns. These attributes differentiate us versus our peer group and provide flexibility to succeed under varying market conditions. We are very well positioned as a company to generate significant sustainable free cash flow over the long-term. With I'll turn the call over the operator for questions.

Thank you. We will now be conducting our question-and-answer session. [Operator Instructions] Our first question comes from Welles Fitzpatrick with SunTrust. Please state your question.

Hey, good morning.

Good morning.

The Utica rig seem to be improving since the last kind of batch you guys disclosed. Is there any chance that the Utica begins to get a little bit larger of a share of CapEx dollars moving forward?

There's certainly a chance. That's something we monitor and we do have a number of Utica locations that are at the very low end of our cost curve. But at the end of the day, you're much better off completing pads in the same general area from an operating and a capital cost standpoint. So right now we're really massed to develop in the very much liquids rich, Marcellus, but we like the Utica as well and we just brought on six dry gas wells, which you probably alluding to in the quarter and those look really strong.

To your point on the Marcellus liquids, it looks like the liquid cap was down a little bit quarter-over-quarter, is that location or is that NGL recovery driven?

I don't believe it was NGL recovery driven. I think you're just going to see a little variants from quarter to quarter on that as we jump from completions at 1240 Btu to the 1275 Btu and back and forth, so that's just going to vary. Those are pretty chunky, obviously, when you bring it on a 10, 12 well pads, so it can impact the quarterly numbers.

Okay, Okay, perfect. And then just one last one for me, the previous multiyear guidance, I think it had something of a 10% to 15% sort of soft guide for growth, but obviously at a much higher commodity price. Should we think – how should we be thinking of that going forward? Obviously, prices are lower, but you're doing a lot to offset that vis-a-vis costs. How should we reframe that moving forward?

Yeah, I think you can see from all the materials in the press release, we're very much focused on that sort of 10% CAGR over the next several years for production growth. So we're not we're not looking at that upside growth case. And in fact, if we see improvement in commodity prices, which we certainly think we will over the coming quarters and years that will just be captured as additional cash flow for deleveraging and other uses not for accelerating the capital plan.

Makes sense, thanks so much for your time.

Thank you.

Thank you.

Our next question comes from Jane Trotsenko with Stifel. Please state your question.

Good morning. I have an easy question to start with. Maybe you can discuss CapEx and production cadence over the remainder of 2019?

I'm sorry; you're asking how much reduction we see in the year 2019?

No, I'm talking about CapEx and production cadence. How should we think about quarter-over-quarter production for 3Q and 4Q and also CapEx spending?

Yeah, well, I mean, you can see we're right at our guidance for the year on production. So I think you'll see that pretty flat through the year and then we expect capital as we as we stated in the in this call, we expect that to run in that $300 million, maybe a little bit over $300 million each quarter, for the next many quarters, really.

Okay, so would it be fair to say that the CapEx spending over the remainder of the year would be pretty spread out, like equally spread out over the remaining two quarters?

Yeah, exactly, I think that's the message Jane, it's pretty flat.

Okay. Okay. And then given very strong QQ production, I'm just curious if that was expected, given the well cadence on your side – given very strong QQ production, how should we think about full year production guidance? Are you expecting now to come in on the high end of the full year production guidance, mid range or maybe low end?

I think the mid range is a good expectation. The quarterly numbers depends a bit on the cadence. And we've been talking bring pads on earlier than expected. And we've also really liked results. So we've seen the productivity of the well, starting to see in some of that, but no, we're not rising to the high end. I think the mid point's a good place to be.

Okay, perfect. And my last question is regarding gathering fees in FTE do you see an opportunity to use gathering fees and maybe offload some of the FTE commitments in the near future?

We always look at that. But so far there is – it's difficult in this environment as prices have contract at the spreads have contracted to so the FTE is less desirable.

Okay, thank you so much.

Thank you.

Our next question comes from Holly Stewart with Scotia Howard Weil. Please state your question.

Good morning, gentlemen.

Good morning.

Maybe just hitting on all the water savings Paul, I think you gave a percent of LOE that produced water made up, but I missed that, what was that number for that percentage?

It was 80%, eight zero percent of LOE.

Okay, big number. And then admittedly, my understanding of the entire water value chain could be better. So with that in mind, can you sort of help us, I mean, I remember it wasn't that long ago that we were talking about using more water per foot in our completions. So I guess what has changed? And then maybe give us a sense for the pilots that you've done so far?

Yeah, well, what has changed as we said in the remarks, really the interaction between wells that you go on wider fracks the more or the fracks go further out away from the well bore, depending on how much water you use? And the converse is, with sand, it's better near bore conductivity, as we say, the fractures are well connected. So we saw that we didn't need to go quite as wide and half length between well bores that we could cut back on the water. What we see across the industry and so we are seeing things just the way the industry is. The 100 mesh is a little bit simpler, we use some of the, the coarser meshes in some of our designs, but we can get the jobs off pretty quickly with virtually no screen outs by going with the 100 mesh. And when we do that, it requires less water. So we were able to cut back just a little bit, 10% or 15%, cut on the water, and stick with mostly 100 mesh on the proppant and that's working well.

Do you have an estimate of how much that specifically is helping in terms of low costs?

We have a component there. Let's see Mike's pulling out his number.

$280,000 per well just on the water and then the actual produced water savings because he have lower produced water because you now put less water in his further 108, so it's about $400,000 in total.

Right, so the first 200 – remember, we were explaining that we call the first 90 days of the water coming back, we call that flow back. And so those costs to truck and clean up are part of the well cost, so that's the 280. And then the next amount that Mike talked about is the LOE savings beyond the first 90 days, but it's material for both, it's definitely an important cash factor for us.

Yeah, that's very helpful. Maybe this is one for you, Glen. I know you talked in detail on the release about utilizing the lower cost FTE as opposed to the higher cost project. So can you just give us some, maybe some color around that? I don't know if you want to reference projects, but just kind of help us understand those comments.

Yeah, the other day, I think our molecules are just chasing the best pricing the best net backs and when you have tight differentials in the basin then you're keeping some of the gas closer to home, and that's what we've seen some in the in the second quarter, I think it's as simple as that.

Okay, okay, that's helpful. And then maybe finally for me, just on a high level, just kind of thoughts around the AM ownership here. And I know historically, you sort of use that to raise, raise capital, at least DT or maybe within happiness 2018. But there's a lot going on with the simplification that year, so maybe just high level thoughts around the AM ownership.

We like the ownership. You can see the $200 million or so of dividend stream and presumably growing over time. So it'd be tough to sell it particularly today at a13% kind of yield. So tough for us to let go, but it's what I'm getting at. So we're not inclined to do anything with it today. And we really enjoy that ownership and see tremendous amount of upside in AM. So I think we'll stand pat for now.

Okay, perfect, thanks guys.

Thank you.

Our next question comes from Bryan Singer with Goldman Sachs. Pleas state your question.

Thank you. Good morning.

Good morning.

Can you talk a bit more of how you see the balance sheet evolving, particularly how you see the options and your own level urgency with regards to debt coming due in2021 and 2022?

Yeah, of course, we've got great rates on those two bonds that you're alluding to. And they come through at the end of each of those years. So we've got almost two and a half years on the 2021 maturity and obviously more like three and a half years on the other one, so no real sense of urgency there. We pick our spots with the bond market. And it's had a tough run in the last month or so and so we'll be optimistic about that. But I think that's not something that keeps us up at night by any means. We've got tremendous amount of liquidity on our credit facility, very strong bank group, more banks wanting to get into our credit facility. So that's all in good shape as far as we're concerned.

Great, thanks. And then just a couple of follow ups to the point you made earlier, the $1.2 billion to $1.3 billion exploration and development budget, what production growth do you expect that to get you in 2020? And then with regards to the $150 million of litigation proceeds, what are the risks if any to the upside or downside with regards to receiving those proceeds or the timeline to receive them?

Yeah, on the on the production, I mean, we talk about a 10% production CAGR and that's a multiyear look. So I think, you can handicap that, give or take 2% or 3% either side of that. But that's kind of the outlook for the next few years. So I think you'll see a sort of average 10% production growth, and that 1.2 billion to 1.3 billion next year keeps us very much on that track. And then similar levels – and we really don't need much of an increase over time over the next few years to deliver that – over that1.2 billion to 1.3 billion range stays in that in that range. So we feel good about that.

And then on the litigation.

On the litigation front, yeah, we wouldn't talk about those publicly if they weren't pretty far down the road. And so there was a jury trial on the biggest piece of that was a utility with WGL. And that ended very much in our favor and they can always – the other side can always appeal, of course, so the time it would be the risk I would say. That could come sooner or could come later. But I think that's a good handicapping in the year 2020.

The other one's South Jersey.

The other one is South Jersey, Brian, you can read about that in 10-K that's pretty well described there, but similar kind of circumstance.

Thank you very much.

Thank you.

Thank you.

Our next question comes from Chandra with the Guggenheim Partners. Please state your question.

Yeah, hi, my word vocabulary is also challenged. So just wanted to ask for some clarification, my understanding at least is that there's a few pathways in the in the water business. One is a disposal cleaning it up to clear water and putting it into I guess, nearby water bodies, et cetera. The other is recycling, and there might be other aspects of it. But could you kind of clarify where these savings are occurring first of all? Second of all, what remaining aspects of the water handling are future challenges? And then finally, is the water stuff discussed on the print today? Is it 100% application or are you easing into it in 2020?

Good question, Subash.

Good questions, yeah.

No, I think that's a good tutorial on what's going on. So I mean I'll turn to Paul. But the first way to think about it, I think is really what we're doing is kind of shortening the loop. as we as we move north in the liquids rich area, I mean, some of that is 25, 30 miles away from some of that development from Clearwater. So you might think of it as rather than taking it all back to Clearwater, where the trucking can be $6, $7, $8 a barrel, we're essentially reusing it right there in the area. So that's always referred to it as local reuse. And it goes right back into the next completion. So just shortening the loop and taking the trucking out. And the fees are also presumed to be a bit lower for the cleanup of the water we're doing locally.

Yeah, that's right, the fees can be lower because the cleanup we can take advantage of blending as well, by just taking the effluent just as Clearwater does, but not doing as duplicate the flow back and produced water and blending it down and using it in future completions. So as Glen said, big savings on the tracking side, because we're keeping it close to where the development is and then big savings on the clean up and that we can use polishing and blending down to be a little more economic.

And then in terms of what we're talking about, we would be completing wells in the liquids rich fairway with call it 75-25 freshwater, and then the clean that water locally and that will vary over time, it can be at 80-20. It's just going to very. We are not blending in some water, just treat it locally is the whole concept. And we'll be doing some of that this year. And I think yeah, Subash asked about proportionally.

Yeah, we're stepping into it. As we speak, we have a number of pads that we are completing here in third and fourth quarters of Cal '19. And those are up in this focus development area to the north. And so we'll be doing those polishing and blending there. And step into it in a more wholesome way through Cal '20.

Okay, so I guess to boil it down the 120 ish well development plan for 2020. Do these water savings apply to all these wells?

If possible, yes. We got16 working to work hard on the logistics, we're fortunate that our acreage position is quite concentrated. So we don't have the issue of pads distant from each other. And so in that way, it's not only efficient for midstream for the hookups. But for water transfer between pads as we flow back one pad, we can use that water right next door to complete the next pad. So nice focus that way and so yes, the goal will be to do it on all 110, 220 wells next year. And apply those savings, not only the well cost savings, but the LOE savings throughout the board.

Okay, I'll let that sink in. I'll probably follow up offline over next couple weeks. Just another follow up on the simultaneous operations, is that on the larger pads, is that pretty common right now? Is that built into the 2020 guidance?

We've done it, we've done it recently, the same maps where we're having either two crews' at once on different ends of the pad and we're completing or we're drilling on one end and completing on the other. But I think we have enough flexibility that we don't have to do that all that often. And there's nothing bunch gap in cycle time. So we're built to do that. But it's probably about 15% of our pads that we do same maps on.

Okay, thank you. Thanks, guys.

Our next question comes from Sean Sneeden with Guggenheim Securities. Please state your question.

Hi, thanks for taking the questions.

Sure, thanks,

Glen, maybe for you just on leverage – picked up a little bit in the quarter, when you think about, trying to maintain where it's been typically a pretty conservative balance sheet, it sounds like in the near term, we're kind of comfortable with level of liquidity and funding the outspend that way, but when you think about different levers, you may have to address and keep leverage in check near term I guess. How are you guys thinking about some of the noncore stuff may have for them Utica or have AM units are slowing down?

Yeah, the slow down, that's not really in the cards. I mean, that's what this is all about right, improving capital efficiencies and reducing well costs and enables us to continue on the pace that we've been talking about. So that's really not something that's being kicked around. And in terms of cash flow, free cash flow needs, the outspend it's in the – over the next three, four years, it's in the several hundred million dollars, not a using stage strap and that's probably due to our hedge profile and all that. So it's not a real big number. So the actual data itself, we don't see that increasing much, it's just that EBITDA has come down a bit for everyone over the past few quarters, with the commodity price coming down. So it's really the denominator that's come down a bit. So we're managing the balance sheet just fine. It's not growing tremendously. And we're very comfortable with where we are. And you'll see us continue to hedge opportunistically as well. As far as, I'm sorry, you mentioned, divestitures or whatever. The door is always open for that, we consider that, we look at those from time to time, but I'd say there's not a big initiative to go out and sell a chunk of our position. We like all of our position and it gives us you know, sort of unparalleled inventory in the innovation. But yes, the door is open for those kinds of things. I don't think they're big needle movers, but could happen.

Understood that that's helpful and then just on ethane, can you remind us what your FTE minimums are there? And is it fair to assume just current prices in strip, you reject above those levels?

Yeah, we're recovering 40,000, 41,000 barrels a day. And much of that is for firm sales. Our FTE, we have 20,000 barrels a day on 8x for ethane transport to Mont Belvieu. We've laid some of that off, so net Antero 10,000 barrels a day, which we're using to facilitate from sales here and there. But we have a number firm sales to two different parties, both internationally and also domestically – internationally, including Sarnia. So we're a little above – our firm sales are a little bit higher than our must recover. But we always have an eye on Btu of the revenue stream coming out of the plants. And we certainly have flexibility to recover more. But right now, as you know, the numbers say reject the ethane, where you can accept, again, to stay within spec and also to fulfill some firm sales on ethane.

Got it, that makes sense. And can you remind us what the average tenure of the firm sales arrangements is?

I would say yeah, 10 to 20 years. I would say and we're a base provider for the upcoming shell cracker just west of Pittsburgh, so that'll be even more supply. And that is a 20 year contract there. And some of our –

It's 15.

Excuse me, 15, but we have international with contracts with Borealis, with Ineos, with others that are typically 10 year contracts.

Perfect. Appreciate the color guys. Thanks.

Thank you.

Our next question comes from Matt Henschke with McGuire [ph]. Please state your question.

Hi, thanks. Your preliminary 2020 comments on free cash flow suggest $275 million outspend excluding onetime items. Can you help provide color on any drivers that may be impacting the outspend other than transport fee assumptions?

Yeah, I think as we outlined early in the call. I don't know if you missed that, but we want to fill our transport and we still have economic drilling to do and so we'll stay in the course rather than simply hit the brakes to generate free cash flow next year. We still have a lot of firm transports to fill next year.

Okay, is there any change in the Btu output assumption or any other assumptions year-over-year or any other color I guess that you can provide?

No, can't think of any.

Okay and then moving on to my last question. I was just wondering if you could provide free cash flow sensitivity to say $1 change in C3+ NGL pricing, given your mention of $29 assumption a bit helps your pricing for next year?

Yeah, if it hits about 100,000 barrels a day, so of that's 365 – it's 36.5 million barrels, so dollar will be about $40 million.

Okay, thanks. That's all I have.

Our next question comes from Ethan Bellamy with Ethan Bellamy with Baird. Please state your question.

Gentlemen, last December, you unloaded some of the 2019 gas hedges? It looks like a rare miss on your hedging strategy. Are you bullish on gas in 2020 on decline rates? And was your timing just off or do the new longer data hedges that you put on in the second quarter stick there as a more pessimistic view on go forward pricing?

Well to be in this business, one has to be optimistic. So we are positive thinkers and optimistic, but we're also defensive. So the hedges that we added were definitely not only a price target, but it's when does it happen. And so just to be protective of the balance sheet we added hedges through Cal '20. You're right. As we monetize some hedges always have an eye on delevering and putting forward the best credit metrics. We were seeing a positive setup in terms of supply and demand when we did that back in December. But yes, in hindsight, that was a miss, we would have been better off to just hold on to those, we wouldn't have paid down the 350 million of debt or so. But we would have – we mark that to market every month or so just to learn from our decisions. And that was one where we would have been maybe $100 million ahead by not doing that.

Yeah, I think it's really – demand has been a bit softer than expected. It's not really been the supply and then just the overall sentiment. So that's kind of caught us off sides, I guess.

Okay. And then, in terms of the strategy, you guys have laid out some nice, seemingly kind of incremental improvements to the business. But that doesn't seem consistent with the kind of urgency I'm hearing from clients about the decline in the stock prices. You address potentially laying off FTE. Are there any other strategic moves available to you like selling acreage potential midstream asset JV sales that might help arrest some of the capital declines and preserve capital here?

Well, there's all of that, but I mean, keep in mind, we're 2.3 times levered and we have well over $1billion of liquidity. So I mean, there's not a real sense of urgency to do those kinds of more dramatic things. And sure, we're always looking at strategic things, a lot of which we can't really talk about publicly until they're done, but we're always working on lots of different alternatives.

Okay, thanks Glen.

Thank you.

Thank you, ladies and gentlemen. I'll now turn it back to Michael Kennedy for closing remarks.

I'd like to thank everyone for joining us today. If you have any further questions, please feel free to reach out to us. Thanks again.

Thank you. This concludes today's conference. All parties you may now disconnect. Have a great day.