Antero Resources Corporation

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. If anyone should require operator assistance during the conference, press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce our host, Michael Kennedy, Senior Vice President of Finance. Thank you. You may begin.

Thank you for joining us for NTERO'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 website at www.nteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Before we start our comments, I'd 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 measure. Joining me on the call today are Paul Rady, Chairman and CEO, and Glenn Warren, President and CFO. I will now turn the call over to Paul.

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 our recently announced well cost and operating cost savings initiatives. I'll provide detail on savings we've achieved to date and highlight the key items that will reduce costs further towards our target. Glenn will then highlight our second quarter financial achievements, including the premium NGL price realizations following our first full quarter with Mariner East II 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 are well positioned to be more flexible with our development plan and generate significant free cash flow. To provide some complex context, if we elect to just maintain year-end 2021 forecast production of approximately four 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 costs 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 to $1.7 million per well by 2020 compared to our 2019 budgeted costs. On a dollar per foot basis, this translates into a reduction from 2019 budgeted costs of $0.97 million per 1,000 feet to a target of $0.83 million to $0.87 million per 1,000 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 to date. Following the waterfall on the page, we begin with our January 19 well cost at $0.97 million per thousand 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 thousand 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 cost deflation that was realized during the first half of 2019. From our current AFE of $0.93 million per thousand feet of lateral, we expect well cost to decline further to the range of $0.83 to $0.87 million per thousand 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 to $1.7 million. We are targeting approximately $800,000 per well in well cost reductions from more efficient flowback and produced water management, as well as optimized completion design. On the flowback 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 fresh water system to transport the water, and three, constructing additional water pipeline infrastructure. Historically, we've used third-party trucking companies to transport our flowback 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 flowback 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 propane, 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 length, driven by water usage, and reservoir conductivity, which is driven by the type and amount of propant, in the most cost-effective manner. We have 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. An 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 an additional sand contract that 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 5,470 feet of lateral drill per day. That's approximately one mile, a 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 9,650 feet of lateral in one day, which we're extremely proud of. Completion stages per day averaged 5.7 stages per day, an increase 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 talk 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 truck 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 truck 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 budgeted costs. This equates to savings of at least $50 million on an annualized basis. Slide number six, titled Appalachian Pier Marcellus Well Cost Comparison, provides a snapshot of our Appalachian Pier well costs and future targets. Keep in mind that there is a variance among producers as to what costs are captured in capitalized well costs 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 cost initiatives have not been fully realized to date, we are 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 spending 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 this 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 costs is expected to deliver 2019 drilling and completion capital at the low end of our guidance range. and lead to a lower DNC capital target of $1.2 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 Glenn for his comments.

Thank you, Paul. The second quarter was the first full reporting period with the Mariner East II pipeline in service, giving us access to premium-priced global LPG prices or markets. We hold about one-third of the current 165,000 barrel a day of capacity on Mariner East II, making us the largest shipper on this pipeline. During the quarter, we realized an unhedged average C3-plus NGL price of $28.57 per barrel for the quarter. That's $1.68 per barrel premium to Mt. Bellevue pricing as shown in slide number seven titled inflection point in the NGL marketing and pricing. Fifty-five percent of C3 plus volumes were exported and realized a $0.19 per gallon premium to Mt. Bellevue pricing. In the table on the right-hand side of the slide, we provide guidance on NGL realizations relative to Mt. Bellevue pricing for the full year As you can see on a blended basis, it's essentially flat to Bellevue to a slightly positive premium of $0.04 per gallon. Now let's take a look at the impact of that ME2 has had on Northeast NGL differentials. Since the in-service of ME2 in February of this year, Ontario's NGL price differentials improved by over $6 per barrel, flipping from a discount to a premium to Mount Bellevue. 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 barrel a day flowing on ME2 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 ME2. ME2 is that dotted vertical line over to the right. First half 2018 realizations averaged at an approximate $5.75 per barrel discount to Mont Bellevue. Despite the softer domestic prices seen during the first half of 2019 versus the prior year, our realized price relative to Mont Bellevue 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 plus NGO price realizations have also improved following the startup of ME2. C3 plus NGL realizations over the past four years have averaged about $7 per barrel. You can see that on the orange line there, discount to Bellevue, but have improved by 30% in the first half of 2019. Looking forward to 2020 with the completion of the full ME2 project expected by the end of 2019, total pipeline capacity will increase to 275,000 barrels a day on ME2. At that time, we have the option to increase our capacity by as much as 50,000 barrels a day in 10,000 barrel a day increments that would take us up to 100,000 barrel a day of firm capacity, which would increase our exposure to international pricing to the 65% to 75% range on Ontario'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 ME2 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 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 Europe prices are at an $0.08 and $0.14 per gallon premium, respectively, to Mont Bellevue net of shipping. I'd like to touch on the NGL macro briefly. The current weak NGL pricing at Mont Bellevue is due to limited export capacity along the Gulf Coast. Although we expect soft prices to persist through the third quarter, we do see Montbellevue 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 has negatively impacted Montbellevue in GL pricing. In the Northeast, the in-service of full capacity on Mariner East 2 will provide increased exports through the Marcus Hood Terminal. We expect these projects to provide upside to domestic prices as well. We also see strengthening of international prices as up to six new PDH plants are expected to be placed in service in China by year end this year, while Europe and India are also expected to complete additional import terminals. In summary, we expect NGL pricing to improve as we see fundamental strengthening in the coming quarters. Turning to slide number nine, titled Peer Leading Hedge Protection, During the second quarter, we added to our 2020 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 each 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 U.S. producer that is 100% hedged on expected natural gas production in 2019, as shown on slides number 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 AEM 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 in 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 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 to $1.3 billion in 2020. The reduced well costs 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 costs led to a reduction in our maintenance capex estimates, turning to slide number 14, titled maintenance and decline rate projections. We now project maintenance capex, that's to keep production flat at 3.2 BCFE a day, to be approximately $670 million. In summary, please turn to slide number 15, titled AR's Built a Resilient Business Model. Despite the macro and market headwinds today, we've 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 that, I'll now turn the call over to the operator for questions.

Thank you. We will now be conducting our question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. That's the star key followed by the one key on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star followed by two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Our first question comes from Wells Fitzpatrick with SunTrust. Please state your question.

Hey, good morning.

Good morning.

The Utica rates 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 a from an operating and a capital cost standpoint. So right now we're really masked 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're probably alluding to in the quarter, and those look really strong.

To your point on the Marcellus liquids, it looked like the liquids cut was down a little bit quarter over quarter. Is that location or was that MGL recovery driven?

I don't believe it was NGL recovery driven. I think you're just going to see a little variance from quarter to quarter on that, you know, as we jump from completions at a 1240 BTU to a 1275 BTU and back and forth. So that's just going to vary. Those are pretty chunky, obviously, when you're bringing on 8, 10, 12 well pads. So it can impact the quarterly numbers a bit.

Okay. Okay. Perfect. And then just one last one from me. The previous multi-year 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. 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 frame that moving forward?

Yeah, I think you can see from all the materials and the press release, we're very much focused on that sort of 10% CAGR over the next several years for for production growth, so we're not looking at that upside growth case. In fact, if we see improvement in commodity prices, which we certainly think we will over the coming quarters and years, that'll 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, 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. Are you asking how much reduction we see in the year 2019?

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

Yeah. I mean, you can see we're right in our guidance for the year on production. So I think, you know, you'll see that pretty flat through the year. And then we expect capital, as we stated on the 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 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. The chain is pretty flat.

Okay, and then, you know, given very strong 2Q production, I'm just curious if that was expected, you know, given the well cadence on your side. You know, given very strong 2Q 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. You know, it does, you know, the quarterly numbers depend a bit on the cadence. And we've been fortunate to bring pads on earlier than expected. And we've also really liked the results that we've seen, the productivity of the wells. So I think you're seeing some of that. But, no, we're not raising to the high end. I think the midpoint is a good place to be.

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

We always look at that, but so far it's difficult in this environment as prices have contracted, the spreads have contracted too, so the FT is less desirable.

Okay. Thank you so much.

Thank you.

Our next question comes from Holly Stewart with Scotia, Howardville. Please state your question.

Good morning, gentlemen.

Good morning, Holly.

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

It was 80%, 80% of LOE.

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 the fracks go further out away from the wellbore, depending on how much water you use. And the converse is with sand, it's better nearbore conductivity. As we say, the fractures are well-connected. So we saw that we didn't need to go quite as wide in half length between well bores, that we could cut back on the water. What we see, of course, the industry, and so we are seeing things just the way the industry is, that 100 mesh is a little bit simpler. We use some of 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. It's 10% or 15% cut on the water and stick with mostly 100 mesh on the propent. And that's working well.

And do you have an estimate of how much that specifically is helping in terms of well cost?

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 you have lower produced water because you now put less water in. It's a 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, Glenn. I know you talked in detail in the release about utilizing the lower cost FT as opposed to the higher cost projects. So, if you could 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, you know, those comments.

Yeah, you know, at the end of the day, I think our molecules are just chasing the best pricing, the best netbacks. 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 second quarter. I think it's as simple as that.

Okay. Okay. That's helpful. And then maybe finally from me, just on a high level, just kind of thoughts around the AM ownership here. I know historically you sort of use that to raise capital at least each year, maybe with the exception of 2018, but there was 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, you know, $200 million or so of dividend stream and presumably growing over time. So, you know, it'd be tough to sell it, particularly today at a 13% kind of yield. So, you know, tough for us to let go of it is what I'm getting at. So, you know, we're not inclined to do anything with it today. And we really enjoy that ownership and see a tremendous amount of upside in AM. So I think we'll stand pat for now.

Okay. Perfect. Thanks, guys.

Thanks, Alex. Thank you.

Our next question comes from Brian Zinger with Goldman Sachs. Goldman Sachs, please 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 of urgency with regards to debt coming due in 2021 and 2022?

Yeah, of course, we've got great rates on those two bonds that you're alluding to. And they come due at the end of each of those years. So, you know, we've got almost two and a half years on the 2021 maturity and obviously, you know, 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 the last month or so. And so we'll be opportunistic about that. But yeah, I think that's not something that keeps us up at night by any means. We've got a 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 follow-ups to the points made earlier. The $1.2 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 production, I mean, you know, we talk about a 10% production K-year, and that's a multi-year look. So I think, you know, you can handicap that, give or take a 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 to $1.3 billion next year keeps us very much on that track. And then similar levels, we really don't need much of an increase over time over the next few years to deliver that over that $1.2 to $1.3 billion range. It stays in that range. So we feel good about that.

And then on the litigation.

On the litigation front, yeah, those, you know, 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 with 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 that the timing would be the risk, I say. I would say, on that. Could come sooner, could come later, but I think that's a good handicapping in the year 2020. The other ones in South Jersey, Brian, you can read about that in the Q or the 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 Subhash Chandra with Guggenheim Partners. Please state your question.

Yeah, hi. You know, my water vocabulary is also challenged. So just wanted to ask for some clarification. You know, my understanding at least is that, you know, there's a few pathways in the water business. One is a disposal, cleaning it up through clear water and putting it into, I guess, you know, 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, and 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 questions.

Good questions.

No, I think that's a good tutorial on what's going on. So, I mean, I'll turn it 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 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, essentially you know reusing it right there in the area so that's why we refer to it as local reuse and it goes you know 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 clear water does but

not doing as deep a cut on the flow back and produced water and blending it down and using it in future completions. So as Glenn said, big savings on the trucking side because we're keeping it close to where the development is and then big savings on the cleanup in that we can use polishing and blending down to be a little more economical.

And then, you know, in terms of what we're talking about, we'd be completing wells in the Liquids Ridge Fairway with, you know, call it 75-25 fresh water and then this cleaned out of water locally. And that will vary over time. It can be 80-20. It's just going to vary a bit. But we are blending in some water that's treated locally is the whole concept. And we'll be doing some of that this year. And I think I should ask 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 both polishing and blending there and step into it in a more fulsome 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've got our logistics team 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 a nice focus that way. So yeah, the goal will be to do it on all 110 to 120 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 the next couple of 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?

You know, we've done it. We've done it recently, the CIMOPS, 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 not much gap in cycle time. So we're built to do that, but it's probably about 15% of our pads that we do side 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.

Glenn, you know, maybe for you just, you know, on leverage, you know, picked up a little bit in the quarter. And when you think about, you know, trying to maintain, you know, what has been typically a pretty conservative balance sheet, you know, it sounds like, you know, in the near term you're kind of, you know, comfortable with the level of liquidity and funding the outspend that way. But when you think about, you know, different levers you may have to, you know, to address, you know, and keep leverage in check near term, you know, I guess how are you guys thinking about, you know, some of the non-core stuff you may have, whether it's Utica or have you, um, you know, AM units or, or slowing down.

Yeah, the, uh, the slowdown, 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, on the pace that we've been talking about. So that's really not something that's being kicked around. And, and in terms of, uh, cash flow, free cash flow needs. The outspend, you know, it's in the, over the next three, four years, it's in the several hundred million dollars. It's not a, you know, using today's strep. And that's partly due to our hedge profile and all that. So it's not a real big number. So the actual debt itself, we don't see that increasing much. It's just that, you know, EBITDA has come down a bit for everyone over the past few quarters with the commodity price coming down. So it's really the 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 optimistically as well.

Got it.

I'm sorry, you mentioned divestitures or whatever. The door's 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 sort of unparalleled inventory in the basin. 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's helpful. And then just on ethane, can you remind us what your FT minimums are there? And is it fair to assume that just the current price 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 FT... We have 20,000 barrels a day on ATEX for ethane transport to Mount Bellevue. We've laid some of that off, so net to Antero, 10,000 barrels a day, which we're using to facilitate firm sales here and there. But we have a number of firm sales to different parties, both internationally and also domestically, internationally, including Sarnia. So... 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 residue 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, except, again, to stay within spec and also to fulfill some firm requirements. firm sales, I think.

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

I would say, yeah, 10 to 20 years, I would say. We're a base provider for the upcoming shellcracker just west of Pittsburgh, so that'll be even more supply, and that is a 20-year contract there, and some of our... Oh, excuse me, 15. But we have international contracts with Borealis, with Ineos, with others that are typically 10-year contracts.

Perfect. I appreciate the color, guys. Thanks.

Thank you.

Our next question comes from Matt Henske with Macquarie. Please state your question.

Hi. Thanks. Your preliminary 2020 comments on free cash flow suggest $275 million outspend, excluding one-time 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're staying the course rather than simply hit the brakes to generate free cash flow next year. We still have a lot of firm transport 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 thank you Eddie.

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

Yeah, looking at, you know, we produce about 100,000 barrels a day, so if that's times 365, that's 36.5 million barrels, so a dollar would be about $40 million.

Okay, thanks. That's all I have.

Thanks, Matt.

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

Gentleman, 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 did the new, longer-dated two hedges that you put on in the second quarter suggest a more pessimistic view on go-forward pricing?

Well, you know, to be in this business, one has to be optimistic. So, you know, we are positive thinkers and optimistic, but we're also defensive. So the hedges that we added were definitely, you know... It's 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 de-levering 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 mess. You know 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, you know, we mark that to market every month or so just to learn and 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, you know, demand has been soft, a little bit softer than expected. It's not really been the supply. and then just the overall sentiment. So that kind of caught us off sides, I guess, a bit.

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 addressed potentially laying off FT. 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 that, but I mean, keep in mind, we're 2.3 times levered, and we have well over a billion dollars in 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, Glenn. Thank you. 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 may disconnect. Have a great day.