Antero Resources Corporation (AR) Q2 2020 Earnings Report, Transcript and Summary

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 a 12,000 foot lateral. Further, these well costs were achieved with only partial vendor cost reductions, savings which we now expect to realize in full beginning in July this last month. Well costs in the second half of 2020 are expected to average $675 per foot assuming a 12,000 foot lateral. This is 5% below our prior well cost target of $715 per foot and 17% below the initial 2020 well cost target. Expected second half well costs of $8.1 million for a 12,000 foot lateral reflect savings of $3.5 million per well relative to our 2019 budgeted well cost. We expect to achieve to achieve net F&D costs of $0.30 per Mcfe in the second half of 2020 assuming an average EUR of 2.7 Bcf equivalent per thousand feet or 12,000 foot lateral, that's roughly $8 million or a 32 Bcf equivalent well before netting royalties. Turning to Slide 5 titled Marcellus Drilling and Completion Efficiencies. Let's highlight the drilling and completion efficiency gains that are helping drive our well costs lower because they are quite dramatic. During the second quarter, we averaged over 6,100 feet drill per day, when drilling the lateral portion of the well, a 12% increase compared to the prior-year quarter. We averaged only 10.4 days to drill and case a 12,000 foot lateral from spud to rig release. Through continuous operating improvements and the move to mostly 100 mesh sand has increased our completion efficiency to an average 8.7 stages per day during the quarter, a significant increase of 23% from the first quarter of 2020. Recently, we set a company record for an entire pad averaging 9.6 stages per day. Finally, our average lateral length drilled has continued to increase each year and averaging 12,897 feet per lateral in the second quarter. Turning to Slide 6 titled Outstanding Drilling Efficiencies, Antero was the first company to drill 10,000 lateral feet in a day. In the second quarter, we set a new U.S. and what we believe to be a world record by drilling 11,253 lateral feet in a 24-hour period. It's noteworthy that 12 of Antero's Top 20 drilling footage days have occurred in 2020, while the top three footage days all occurred in the last 30 days. This highlights the significant operational gains our team has delivered this year and in particular the momentum that continues today. I'm extremely proud of the job Antero's operating team has done optimizing our drilling and completion operations and in delivering significant cost reductions. These integrated efforts led to our lowest quarterly capital spend since our IPO in 2013 at $180 million. At mid-year, we have already completed 66% of our expected 105 completions in 2020, so we anticipate a decline in capital spending each subsequent quarter in 2020. As you can see on Slide 7, titled Efficiency and Cost Momentum Leads to Lower Capital, our $750 million 2020 capital budget is 41% below the 2019 capital budget and 35% below the initial 2020 budget set in February of this year. Importantly, we expect to generate approximately $200 million of free cash flow during the second half of 2020 based on today's strip prices. With that, I will turn it over to Dave Cannelongo for his comments. Dave is our Vice President of Liquids Marketing & Transportation. Dave?

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 NGL prices is set up for improved pricing as we head into next year; the limited liquidity in the futures markets for such products does not always reflect the anticipated value further out the curve. Or put another way, there is typically very little correlation between the future strip price in the out years and the ultimate physical price. Slide number 10 titled NGL Pricing Outlook illustrates the value of some third-party analytical teams, including the Citibank Commodities team shown here are placing on NGLs in 2021 and beyond based on their bottoms up global supply demand models. Looking more closely at the Northeast takeaway capacity, Slide number 11 titled, Northeast LPG Supply & Demand highlights the reason for a tightening of the Northeast differentials to Mont Belvieu for LPG that has resulted from the Mariner East project. The increase in takeaway capacity out of the Marcus Hook terminal through Mariner East led to markedly improved in basin pricing relative to Mont Belvieu. Marcus Hook has the capacity to evacuate in excess of 225,000 barrels a day of LPG from the basin through exports helping support Northeast domestic LPG prices. The anticipated final completion to the Mariner East 2 pipeline system this winter taking ME2 capacity to 275,000 barrels a day will create ample capacity to export Northeast NGL production for the next several years. And we anticipate in-basin differentials to remain tied to Mont Belvieu going forward. With that, I'll turn it over to Glen.

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 that's about midway down the page there. On Slide number 14 completions you can see an even greater 79% decline in total U.S. completion spreads in the oil focused space also in the middle of the page there. This sharp reduction in activity that became widespread during the second quarter is expected to result in further declines in natural gas and NGL supplies moving into the second half of this year, as decline rates begin to take hold. Note that 65% of U.S. NGL supply comes from shale oil focused basins compared to only 27% of natural gas supply from those basins. This indicates that the dramatic slowdown in activity in the oil focused shale basins will have an even larger impact on NGL supply than it will on natural gas supply. These are some of the fundamentals behind the NGL slides that Dave discussed earlier. Slide number 15 titled, Asset Sales Program Update provides a recap of our asset sale progress. In total, we've announced $531 million of asset sales to-date. This includes the sale of $100 million of AM common shares last December, the $402 million royalty transaction that we announced in June, and the $29 million hedge monetization announced today. The hedge monetization was executed to bring our hedge book back to alignment with our net volume forecast, following the royalty transaction, assuming our maintenance level capital plan for 2021. We continue to stay focused on executing our asset sale target range of $750 million to $1 billion. Slide number 16 titled Asset Monetization Opportunity Set details the range of options that are being considered. We have delivered 60% of the mid-point of that target thus far and are in substantive discussions on several of these options and remain confident that we will achieve our asset sales target this year. Slide number 17 titled Substantial Liquidity Enhancements illustrates our updated liquidity outlook. We continue to be proactive with debt repurchases during the second quarter repurchasing $279 million of notional debt at an 18% weighted average discount. Since the start of our debt repurchase program in the fourth quarter of 2019, we have repurchased $888 million of notional debt at a 19% weighted average discount, thereby reducing total debt by $171 million and annual interest expense by about $24 million. There's a table in the Appendix that gives you more detail. The remaining market value of the 2021 and 2022 senior notes net of what has been repurchased today is shown on the right hand side of Page 17 and totals $1 billion. Pro forma for the hedge monetization and debt repurchases AR had just under $1 billion of liquidity as of June 30, 2020, which is shown on the dark green bar on the left hand side of the page. We anticipate generating $200 million of free cash flow in the second half of the year based on today's strip prices, providing additional liquidity to reduce debt. Assuming execution of our asset sale program at the top end of $1 billion, we would have over $1.7 billion in liquidity at year-end 2020, more than sufficient to handle both the 2021 and 2022 maturities, which have a total par value just under $1.3 billion. In conclusion, the progress of our asset sales program, significantly de-risked our credit profile, enables us to manage our upcoming senior note maturities. Additional asset sales and expected free cash flow during the second half of 2020 is expected to increase our liquidity at year-end 2020. Our reduced cost structure supports a low maintenance capital level of just $600 million to hold 2020 average volumes of 3.5 Bcf a day flat in 2021, which will preserve liquidity and maximize free cash flow. These are historic times and we continue to execute on our cost savings initiatives and debt reduction program despite the challenges driven by the COVID-19 pandemic, a true testament to the dedication of Antero's employees. With that, I'll now turn over the call to the operator for any questions.

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.