Greetings, and welcome to the Antero Resources Second Quarter 2020 Earnings Conference Call. At this time, all participants are in a listen only mode. A brief question and answer session will follow the formal presentation. 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 Q2 2020 investor conference call. We will spend a few minutes going through the financial and operational highlights and then we will open it up for Q and A. I would also like to direct you to the homepage of our website at www.anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Before we start our comments, I would first like to remind you that during this call, Antero Management will make forward looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero and are subject to a number of risks and uncertainties, many of which are beyond Antero's control.
Actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Today's call may also contain certain non GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman and CEO Glenn Warren, President and CFO and Dave Conalango, Vice President of Liquids Marketing and Transportation. I will now turn the call over to Paul.
Thank you, Mike. I will open by commenting on the progress we have made on our asset sale program. We have announced $531,000,000 of asset sale proceeds to date, which is over half of our $750,000,000 to $1,000,000,000 target for 2020. The proceeds we have received to date have enabled us to reduce debt by approximately $365,000,000 since the asset sale program began in the Q4 of 2019. During the same period, we repurchased 37,000,000 shares of AR stock at an average price of 1.75
dollars per share. We continue
to be engaged in additional asset sale discussions, which Glenn 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 $3,200,000 per well cost reduction in 2020 relative to our initial 2019 capital budget. This equates to roughly $335,000,000 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 and A make up the remaining savings of to be reduced by more than $600,000,000 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 June well costs averaging approximately $6.95 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 twenty twenty are expected to average $6.75 per foot assuming a 12,000 foot lateral. This is 5% below our prior well cost target of $7.15 per foot and 17% below the initial 2020 well cost target.
Expected second half well costs of $8,100,000 for a 12,000 foot lateral reflect savings of $3,500,000 per well relative to our 2019 budgeted well cost. We expect to achieve net F and D costs of $0.30 per Mcfe in the second half of twenty twenty, assuming an average EUR of 2.7 Bcf equivalent per 1,000 feet for a 12,000 foot lateral. That's roughly $8,000,000 for 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 Q2, we averaged over 6,100 feet drilled per day when drilling a 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. The 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 Q1 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 2nd 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. 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 3 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 am 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 $180,000,000 At midyear, we have already completed 66 percent 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 $750,000,000 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 $200,000,000 of free cash flow during the second half of twenty twenty 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 and Transportation. Dave?
Thanks, Paul. Let's turn to slide number 8 and begin by discussing the NGL macro environment. The effects of COVID-nineteen on oil and transportation fuel demand and the resulting decline in rig and completion crew activity in oil focused shale basins has 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 and fractionated just prior to the onset of COVID-nineteen around the world. The chart on the left hand side of the slide illustrates that NGL supply forecasts have declined by over 1,000,000 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-nineteen levels as the momentum of production declines from the dramatic slowdown in U.
S. Shale activity over the last 4 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 tighten 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 system. While the fundamental backdrop for NGL markets,
we are
seeing a significant
impact on the Mariner East system. While 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. 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 that 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 and 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 of the Meritor 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 tight to Mont Belvieu going forward. With that, I will turn it over to Glenn.
Thank you, Dave. A bullet NGL price outlook is very encouraging for Antero due to our position as the 2nd largest NGL producer in the U. S, producing 131,000 barrels a day of C3 plus in the Q2 of this year. At that production level, a $5 per barrel or $0.12 per gallon change in C3 plus pricing has a $225,000,000 impact on our cash flow. Including hedges, we realized approximately $20 per barrel for C3 Plus in the second quarter.
So a move to even $25 per barrel Continuing on the macro theme shown on Slide number 12, we are 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 canceled 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 of shorter duration than on oil, leading to an undersupplied gas market in 2021. Slide number 13 highlights the sharp 72% decline in horizontal rig counts in the oil focus basin, that's about midway down the page there. On Slide 14, completions, you can see an even greater 79% decline in total U. S. Completion spreads in the oil focus basin 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 percent 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 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 $531,000,000 of asset sales to date. This includes the sale of $100,000,000 of AM common shares last December, the $402,000,000 royalty transaction that we announced in June and the $29,000,000 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 $750,000,000 to $1,000,000,000 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 sale target this year. Slide 17 titled Substantial Liquidity Enhancements illustrates our updated liquidity outlook. We continue to be proactive with debt repurchases during the Q2, repurchasing $279,000,000 of notional debt at an 18% weighted average discount.
Since the start of
our debt repurchase program in the Q4 of 2019, we have repurchased $888,000,000 of notional debt at a 19% weighted average discount, thereby reducing total debt by $171,000,000 and annual interest by about $24,000,000 There's a table in the appendix that gives you more detail. The remaining market value of the 2021 2022 senior notes net of what has been repurchased to date is shown on the right hand side of Page 17 and totals $1,000,000,000 Pro form a for the hedge monetization and debt repurchases, AR had just under $1,000,000,000 of liquidity as of June 30, 20 20, which is shown on the dark green bar on the left hand side of the page. We anticipate generating $200,000,000 of free cash flow in the second half of the year based on today's trip prices, providing additional liquidity to reduce debt. Assuming execution of our asset sale program at the top end of $1,000,000,000 we would have over 1 point of liquidity at year end 2020, more than sufficient to handle both the 2021 2022 maturities, which had a total par value of just under 1.3 $1,000,000,000 In conclusion, the progress of our asset sale program significantly de risked our credit profile, and enables us to manage our upcoming senior note maturities.
Additional asset sales and expected free cash flow during the second half of twenty twenty is expected to increase our liquidity at year end 2020. Our reduced cost structure supports a low maintenance capital level of just 600,000,000 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-nineteen pandemic, the
Thank you. We will now
have a question and answer session at this time. Our first question comes from Welles Fitzpatrick with SunTrust. Please proceed with your question.
Hey, good morning.
Hi, Will.
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 'twenty one program?
I think that's still yet to be determined. There is 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 $2,023.50 and change for 2022. So 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 will be a tough call, but we certainly have that optionality.
Okay. And then to your point about the strip, obviously, it's moved up, your costs have moved in. At what point do you get tempted to put a second rig to work here? And if you don't, how long can you run 2 crews and one rig until you run out of kind of backlog on the DUC side?
Yes, good question. The 2 crews, I think earlier in the year, we had said 1 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 AAM. So just a little bit of balancing going on there. But I think the remainder of the year after those 2 pads we will have just one completion crew. And yes, at this point there is no temptation change our plan.
We are 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. Perfect. Perfect. Makes sense.
Thank you.
Thank you. Our next question comes from Holly Stewart with Scotia Howard Weil. Please proceed with your questions.
Good morning, gentlemen.
Good morning, Holly.
Maybe just start off on the well cost target, it looks like second half well cost target is $6.75 per foot. Can you provide just the first half average, so we have a comparable there?
I believe the first half was probably in the $7.15 a foot range, Holly, and then we expect to be, you said, dollars 6.75 in the second half and ending up the year right in that just over $700 a foot, I believe.
Yes. But I would add May June was below $700 a foot. So we are well below that $7.15 today.
Yes. Okay, great. Thank you. And then maybe Glenn, 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 a previous call, we said that we see a pathway potentially to 650 foot and I think that's still probably a pretty good target. We certainly have plenty of efficiency initiatives still underway and some other ideas. So, we can potentially go lower than that, but right now, 650 is maybe a good target for next year.
Okay, great. Thank you. And then, maybe just looking at that second half free cash flow target of $200,000,000 besides the AM distributions, is there any one timers in there?
There is not. It does not include the $51,000,000 from the override sale. That's not included the judgment, the lawsuit judgment is not included. We're just modeling that into next year for conservatism. So, no, there is nothing else.
Okay, great. Thank you, guys.
Thank you.
Thank you. Our next question comes from Gregg Brody with Bank of America. Please proceed with your question.
Good morning, guys. Hi, Gregg. Good morning.
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 $51,000,000 override payment, no.
No, I mean, the royalty that you owe?
It is net of the overall
Oh, yes, absolutely net. Yes. When we talk about free cash flow numbers, it's certainly a 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 over this year?
2nd quarter was $3,000,000 and going forward for the second half, it's around $30,000,000 to $35,000,000
Got it. So that's $200,000,000 is net of that. Correct. You mentioned double GL litigation. You are expecting that to push out to 'twenty one now?
Yes. Yes, I think
the whole COVID shutdown has not been friendly to that process. So, we are expecting it more like next year, but there is not a lot of certainty around that. So we're not including it this year.
Great. And then as you're reducing activity, do you expect that significant accrued CapEx repayment?
That actually came in the second quarter. We had about a $90,000,000 investment in working capital this quarter. So you saw the big jump, as mentioned in the second quarter, because you went from 3 $20,000,000 of D and C capital down to $180,000,000 in the 1st and second quarter. So that really occurred in May June.
Got it. So that makes sense. I saw the big jump, so you don't expect anything more.
Yes. That's a one timer. That's behind us now. Probably goes the other way a little bit going forward. Yeah, hopefully.
Got it.
Maybe just talking about you mentioned all the asset sales opportunities. Are you confident in 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 are looking at items really across those four columns on the page where we outlined asset sales. So it's not optimizing. These things take time and that's why we gave ourselves the year to complete. We knew there'd be volatility.
We never anticipated the volatility that we've seen this year. But we hit 60% of the midpoint of the target so far. So pretty compelling track record. So we feel confident that we'll get the rest of that this year.
Great. That's it for me. I will jump back in the queue. Thanks guys. Thanks.
Thanks Greg.
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.