Greetings and welcome to the Antero Resources Second Quarter 2020 Conference 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, Michael Kennedy, Senior Vice President of Finance. Thank you. Mr. Kennedy, you may begin.

Thank you for joining us for Antero's second quarter 2020 investor conference call. We'll spend a few minutes going through the financial and operational highlights and then we'll open it up for Q&A. I'd also like to direct you to the home page of our website at www.anteroresources.com where we have provided a separate earnings call presentation that will be reviewed during today's call. Before we start our comments, I would first like to remind you that during this call, Antero management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero and are subject to a number of risks and uncertainties, many of which are beyond Antero's control. Actual outcomes and results could materially differ from what is expressed, implied, or forecast in such statements. Today's call may also contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman and CEO; Glen Warren, President and CFO; and Dave Cannelongo, Vice President of Liquids Marketing & Transportation. I will now turn the call over to Paul.

Thank you, Mike. I'll open by commenting on the progress we've made on our asset sale program. We have announced $531 million of asset sale proceeds to-date which is over half of our $750 million to $1 billion target for 2020. The proceeds we have received to-date have enabled us to reduce debt by approximately $365 million since the asset sale program began in the fourth quarter of 2019. During the same period, we repurchased 37 million shares of AR stock at an average price of $1.75 per share. We continue to be engaged in additional asset sale discussions, which Glen, will highlight in his remarks, and we remain confident that we will achieve our targeted proceeds in 2020. Now let's turn to our progress in reducing Antero's cost structure, which is detailed on Slide number 3 titled cost reduction momentum. Over half of AR's cost savings in 2020 are expected to come from lower well costs, as we have driven a $3.2 million per well cost reduction in 2020 relative to our initial 2019 capital budget. This equates to roughly $335 million in total well cost savings based on our development plan that assumes 105 completed wells in 2020. Lower midstream fees, net marketing expense, LOE, and G&A make up the remaining savings of approximately $280 million. In total, we expect our capital and operating cost structure to be reduced by more than $600 million in 2020, as compared to 2019, resulting in a much improved free cash flow profile. Now, let's get a little more granular with Slide number 4 titled Marcellus Well Cost Reductions, which provides an update to our Marcellus well cost targets. Our well cost savings initiatives continue to drive costs lower with May and June well costs averaging approximately $695 per foot normalized to…

Thanks, Paul. Let's turn to Slide number 8 and begin by discussing the NGL macro environment. The effects of COVID-19 on oil and transportation fuel demand and the resulting decline in rig and completion crew activity in oil focus shale basins have set up expectations of a prolonged period of depressed U.S. oil production. More notably, this backdrop results in depressed associated NGL production relative to the volumes that were being produced in fractionated, just prior to the onset of COVID-19 around the world. The chart on the left hand side of the slide illustrates that NGL supply forecasts have declined by over 1 million barrels a day since the beginning of this year. Further, it highlights that it may take several years for U.S. NGL production to return to pre-COVID-19 levels, as the momentum of production declines from the dramatic slowdown in U.S. shale activity over the last four months plays out. The chart on the right hand side of the slide highlights that sufficient export capacity along the Gulf Coast has helped clear the domestic market and tightened Mont Belvieu pricing to international pricing. Turning to Slide 9 titled NGL Price Recovery Expected, we can see that the strength of NGL markets relative to WTI and Brent has continued to stay elevated as a result of more resilient petrochemical and residential commercial markets during this pandemic. Here we illustrate the outperformance of Mont Belvieu propane relative to WTI in 2020. On the right, we see a similar outperformance in propane relative to Brent at the Far East Index, or FEI which is the benchmark in Asia. This is important as Antero has exposure to not only domestic NGL markets, but also international destination pricing through our export access on the Mariner East system. Well, the fundamental backdrop for…

Thank you, Dave. A bullish NGL price outlook is very encouraging for Antero, due to our position as the second largest NGL producer in the U.S., producing 131,000 barrels a day of C3+ in the second quarter of this year. At that production level, a $5 per barrel or $0.12 per gallon change in C3+ pricing has a $225 million impact on our cash flow. Including hedges we realized approximately $20 per barrel for C3+ in the second quarter, so moved even $25 per barrel increases our annual cash flow by $225 million. So we have significant pricing leverage. Continuing on the macro theme shown on Slide number 12, we're also encouraged by the natural gas macro outlook for the second half of 2020, and into next year, following the dramatic decline in industry rig counts and completion spreads. 2020 natural gas production is forecast to exit approximately 5.5 Bcf a day lower than 2019. This reduced activity is expected to extend supply declines into 2021, with average production, projected to be 8 Bcf a day below the 2019 peak. On the demand side, we have seen an impact from the global pandemic on natural gas but primarily through cancelled LNG cargoes, as U.S. residential and commercial demand has remained strong driven by above average temperatures this summer. LNG cargo cancellations are forecast to moderate in September, but only about half of August cargo cancellations expected. So that's up to 3 Bcf a day of uptick in LNG demand expected for September. The pandemic impact on natural gas demand is expected to be less strong or impactful and a shorter duration than in oil leading to an undersupplied gas market in 2021. Slide number 13 highlights the sharp 72% decline in horizontal rig counts in the oil focused space and…

Thank you. We will now have a question-and-answer session at this time. [Operator Instructions]. Our first question comes from Welles Fitzpatrick with SunTrust. Please proceed with your question.

Just a quick one on the liquids recovery, you guys had contemplated potentially doing some more dry gas pads, I think you had a couple in the Utica, are the strips at a point where those are put on the back burner again, or do you think those could feature in your 2021 program?

I think that's still yet to be determined. They're certainly nice pads that we can build in and increase our dry gas exposure and the strip has improved, as you know, it's up over $2.73 I think for 2021, and $2.50 and change for 2022. So that that's attractive, but we also see a lot of strength in the NGL pricing as we discussed a little bit earlier. So I think it'd be a tough call, but we certainly have that optionality.

Okay. And then to your point about the strip out, if it's moved on if your costs have moved in, at what point will you get tempted to put a second rig to work here. And if you don't how long can you run two crews and one rig until you run out of kind of backlog on the debt side?

Yes, good question. The two crews I think earlier in the year, we had said one completion crew for the rest of the year. But we did bring another crew back to address a couple of pads, just to balance our spending and production for the year to hit our LP targets on gas for our rebates from AM, so just a little bit of balancing going on there. But I think the remainder of the year after those two pads we'll have just one completion crew. And yes, at this point, there's no temptation to change our plan. We're pretty fixated on free cash flow and maintenance capital level flat production, so not even considering that at this point. As you know, we have debt maturities to address and we want to bring our absolute total debt down. So that's really the first use of free cash flow.

Thank you. Our next question comes from Holly Stewart with Scotia Howard Weil. Please proceed with your questions.

Maybe just start-off on the well cost target, it looks like second half well cost target is 675 per foot, can you provide just the first half average we have a comparable there?

I believe the first half was probably in the $715 foot range, Holly, and then we expect to be like you said $675 in the second half ending up the year right in that just over $700 a foot I believe.

Yes, but I would add May and June was below $700. So we're well below that $715 today.

Yes, okay great. Thank you. And then maybe, Glen, how much further do you think well cost has to go as you kind of look to 2021?

Yes, that's a great question. I think on our previous call, we said that we could see a pathway potentially to 650 foot and I guess they'll probably have a pretty good target. We certainly have plenty of efficiency initiatives still underway and some other ideas so could potentially go lower than that. But right now, 650 is may be a good target for next year.

Okay, great. Thank you. And then maybe just looking at that second half, free cash flow target of $200 million besides the AM distributions, is there any one-timers in here?

There's not. It does not include the $51 million from the override sale. That's not included. No, the judgment, the lawsuit judgment is not included. We're just modeling that into next year for conservatism, so now it's nothing else.

Thank you. Our next question comes from Gregg Brody with Bank of America. Please proceed with your question.

Just following up on that free cash flow question does that number include the payment for the ROI for the overriding royalty interest?

It does not include the override, the $51 million override payment, no.

No, I mean, the -- your -- your royalty that you owe?

It is [indiscernible].

Yes, absolutely. Yes, when we talk about free cash flow numbers, it’s certainly net free cash flow number. That's right.

And that's going to be coming through in the cash flow statement going forward as a financing activity, correct?

That's right. It's a one-line item in the cash flow statement.

How much should we think about that being for this year?

Second quarter it was $3 million. And then going forward for the second half is around $30 million to $35 million.

Got it. So that's [indiscernible] that. You mentioned the WGL litigation; you're expecting that to push out to 2021 now?

Yes, I think the whole COVID shutdown has not been friendly to that process. So we're expecting it to more like next year, but there's not a lot of certainty around that. So we're not including this year.

Right. And then as you are reducing activity, do you expect a significant accrued CapEx prepayment?

That actually came in the second quarter; we had about a $90 million investment in working capital this quarter. So you saw the big jump, as mentioned in the second quarter because you went from $320 million of D&C capital down to 180 in the first, second quarter. So that really occurred in May, June.

Got it. So that makes sense. I saw the big drop in C&R, don't expect anything more.

Yes. That's a one-timer that's behind us now and probably goes the other way a little bit going forward.

Got it. Just maybe just talking about you mentioned all the asset sales opportunities. You're confident in your asset sales for the rest of the year? Is there anything that's a leading candidate that we should be thinking about?

No, I think we're looking at items really across those four columns on the page where we outlined asset sales. So it's all about optimizing and these things take time and that's why we gave ourselves a year to complete. We knew there'd be volatility. We never anticipated the volatility that we've seen this year. But we've hit 60% of the mid-point of the target so far, so, pretty compelling track record. So we feel confident that we'll get the rest of that this year.

Thank you. There are no further questions. At this time, I'd like to turn the floor over to Michael Kennedy for any closing remarks.

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

Ladies and gentlemen, this concludes today's web conference. You may now disconnect your lines at this time. Thank you for your participation and have a great day.