Q2 2020 Antero Resources Corp Earnings Call
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It is now my pleasure to introduce your host Michael Kennedy Senior Vice President Finance. Thank you Mr. Kennedy you may begin.
Thank you for joining us for Antero second quarter 2020, Investor Conference call.
Well spend a few minutes going through the financial and operational highlights and then we'll open it up queuing <unk>.
I'd also like direct you to the home page of our website at Www Dot Antero resources Dot com.
Where we have provided a separate earnings call presentation that will be reviewed during today's call.
Before we started our comments I would first like to remind you that during this call and Taro management will make forward looking statements such statements are based on our current judgments regarding factors that will impact the future performance have been Carol.
Our subject a number of risks and uncertainties many of which are beyond anteros control.
Actual outcomes results could materially differ from what is expressed or 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 remote.
Comparable GAAP financial measures.
Joining me on the call today, our Paul Reighty, Chairman and CEO.
Glenn Warren President and CFO, and Dave caught a long ago, Vice president of liquids marketing and transportation.
Ill now turn the call over to Paul.
Thank you Mike.
Oh open like commenting on the progress we've made on our asset sale program.
We have announced $531 million of asset sale proceeds today, which is over half of our 750 million to 1 billion dollar target for 2020.
The proceeds we have received to date have enabled us to reduce debt.
Proximately $365 million since the asset sale program began.
The fourth quarter of 29 team.
During the same period, we repurchased 37 million shares a our stock at an average price of $1.75 grew 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 lets turn it to our progress in reducing anteros cost structure, which is detailed on slide number three titled cost reduction momentum.
Over half of a ours cost savings in 2020 are expected to come from lower well cost.
As we have driven a 3.2 million dollar 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 Aloe Lee and GE today make up the remaining savings of approximately $280 million.
In total we expect our capital and operating cost structure could be reduced by more than $600 million in 2020 as compared to 29 team.
One thing in a much improved free cash flow profile.
Now, let's get a little more granular.
Slide number four titled Marcellus well cost reductions.
Which provides an update to our Marcellus well cost targets.
Our well cost savings initiatives continue to drive cost lower.
With man June well cost, averaging approximately $695 per foot normalized to a 12000 foot lateral.
Further these well costs were achieved with only partial vendor cost reductions.
Savings, which we now expect to realize in fall beginning in July this last month.
Well costs in the second half of 2020 are expected to average $675 per foot assuming at 12000 foot lateral.
This is 5% below our prior well cost target of $715 per foot.
And 17% below the initial 2020 well cost target.
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Expected second half well costs of.
$8.1 million for a 12000 foot lateral.
[noise] reflect savings of $3.5 million per well relative to our 2019 budgeted well cost.
We expect to cheat to achieve net FNB cost.
30 cents per Mcf fee in the second half of 2020.
Assuming an average you are up 2.7 bcf equivalent per thousand feet or until 12000 foot lateral.
Thats roughly $8 million for a 32 bcf equivalent well before netting royalties.
Turning to slide five.
Titled.
Marcellus drilling and completion efficiencies.
Lets highlight the drilling and completion efficiency gains that are helping drive our well cost lower because they are quite dramatic.
During the second quarter, we averaged over 6100 feet drilled per day when drilling the lateral portion of the well at 12% increase compared to the prior year quarter.
We averaged only 10.4 days to drill and case at 12000 foot lateral from spud to 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 first quarter of 2020.
Recently, we set a company record for an entire pad, averaging 9.6 stages per day.
Finally, our average lateral lengths drilled has continued to increase each year and averaging 12897 feet per lateral in the second quarter.
Turning to slide six titled Outstanding drilling efficiencies Antero as the first company to drill 10000 lateral feet in a day.
In the second quarter, we set a new U.S. and what we believed to be a world.
A record by drilling 11253 lateral feet in a 24 hour period.
It's noteworthy that 12 of anteros top 20 drilling footage days have occurred at 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 anteros 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 seven.
Idled efficiency and cost momentum leads to lower capital our 750 million dollar 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 can along though for his comments.
Dave is our vice president of liquids marketing and transportation Dave.
Okay.
Thanks, Paul.
Let's turn to slide number eight and begin by discussing the NGL macro environment.
The effects of Cobot 19 on oil and transportation fuel demand and the resulting decline in Reagan completion crew activity in oil focused shale basins as set of expectations are prolonged period of depressed us 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 cobot 19 around the world.
Chart on the left hand side of this slide illustrates the NGL supply forecasts have declined by over 1 million barrels a day since the beginning of this year.
Further and highlights that it may take several years for us NGL production to returned to pre koeppen 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 a sufficient export capacity along the Gulf Coast has helped clear the domestic market and tighten Mont belvieu pricing to international pricing.
Turning to slide nine titled NGL price recovery expected, we can see that the strength of NGL markets relative to WT. 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 in Mont Belvieu propane relative.
In 2020 on the right, we see a similar outperformance in propane relative to Brent at the far East index or FBI, 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.
While the fundamental backdrop for NGL prices is set up for improved pricing as we head into next year, a limited liquidity in the future as markets for such products. That's 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 busy.
Price slide number 10 title 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 take away capacity slide number 11 title 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 do evaluate an excess of 225000 barrels a day of LPG from the basin through exports, helping support northeast domestic LPG prices.
Anticipated final completion of the Mariner East two pipeline system. This winter taking on me two capacity to 275000 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'll turn it over to Glenn.
Thanks.
Thank you, Dave a bullet NGL price outlook is very encouraging for antero due to our position as the second largest NGL producer in the US producing 131000 barrels a day of C plus in the second quarter of this year.
At that production level, a $5 per barrel or 12 cents per gallon change in C. Plus pricing has a 225 million dollar impact on our cash flow.
Including hedges, we realized approximately $20 per barrel for C plus 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 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 eight Bcf a day below the 2019 peak.
On the demand side.
We have seen an impact from the global pandemic on natural gas for primarily through canceled LNG cargoes as us residential and commercial demand has remained strong driven by above average temperatures. This summer.
LNG cargo cancellations are forecast to moderate in September.
With only about half of August cargo cancellations expected, so thats up to three Bcf a day of uptick in LNG demand expected for September.
Depend dimmick impact on natural gas demand.
Is expected to be less strong or impactful and have shorter duration that 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 focused space and Thats about mid way down the page there on slide number 14 completions you can see an even greater 79% decline in total us completion spreads in the oil focused space and also.
In the middle of the page there.
This sharp reduction in activity that became widespread during the second quarter is expected results 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 us NGL supply comes from shale oil focused basis 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 titles.
Asset sales program update provides a recap of our asset sale progress in total we've announced $531 million of asset sales. Today. This includes the sale of $100 million of a in common shares last December the 402 million dollar royalty transaction that we announced in June.
And the $29 million hedge monetization announced today.
Monetization was executed to bring our hedge but 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 title asset monetization opportunity set details the range of options that are being considered.
We have delivered 60% of the midpoint 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 number 17 title 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. The fourth quarter 2019, we have repurchased $888 million of notional debt at a 19% weighted average discount, thereby reducing total debt by $171 million annual interest expense by about $24 million. There is a table in that.
Index that gives you more detail the remaining market value of the 2021 and 2022 senior notes net of what has been repurchase today is shown on the right hand side, the page 17 and totals $1 billion.
Former for the hedge monetization and debt repurchases, Hey are our head just under $1 billion liquidity as of June Thirtyth 2020, which is shown in 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 and liquidity at year end 2020 more than sufficient to handle both the 2021 and 2022.
Maturities, which had a total par value just under $1.3 billion.
In conclusion, the progress of our asset sale program significantly de risk our credit profile enables us to manage our upcoming senior note maturities additional asset sales expected free cash flow. During the second half of 2020 is expected to increase our liquidity at year end 2020 are reduced cost structure. So.
It's 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 our cost savings initiatives and debt reduction program. Despite the challenges threatened by the Koby 19 pandemic a true Testament to the dedication of anteros employees with that I'll now turn over the call to the operator for questions.
Thank you.
Have a question answer session at this time.
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Our first question comes from Welles Fitzpatrick with Suntrust. Please proceed with your question.
Hi, good morning.
Hi wells.
Just just a quick one on the liquids recovery you guys had contemplated potentially doing some more dry gas path I think I think you had a couple in the Utica.
Our the strips at a point, where those are or.
Good on the back burner again or do you think those could feature in your 21 program.
I think thats still yet to be determined.
There are certainly nice pads that we can build and increase our dry gas.
Exposure and the strip has improved as you know it's up over to $72. A 73 cents I think for us for 2021, and 250 and change for 2022, So that's attractive but we also see a lot of strengthen the NGL pricing as we discuss a little bit earlier, so I think it will.
A tough call, but we certainly have that optionality.
Okay and then.
To your point about the strip obviously, it's moved on to your cost of momentum.
What I would point you get tempted to for the second rig to work here and if you dental how how long can you run two crews and one rig until you run out of run out of kind of backlog on the dockside.
Yes. Good question. The two crews I think earlier in the year. We had said one completion crew for the rest of year, but we we did bring another crew back to address a couple of pads just to balance our spending in production for the year to hit our.
LP targets on gas for our.
Rebates from from a so I just little bit of balancing going on there, but I think the remainder of the year. After those two pads will have just one completion crew and yes. At this point there is no temptation to to change our plan were pretty fixated on free cash flow and.
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.
Free cash flow.
Perfect perfect makes sense. Thank you.
Thank you.
Next question comes from Holly Stewart with Scotia, Howard Weil. Please proceed with your questions.
Good morning, gentlemen.
Right.
Maybe maybe just start off.
On the well cost target it looks like second half well cost target of six.
75 per foot can you provide just the first half average so we have a comparable there.
I believe the first half was probably the $715 a foot range.
Holly and then we expect to be like you said 675 of the second half and adding 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 were well below that 715 today.
Yes, Okay, great. Thank you and then maybe Glenn how much further do you think well costs have together as you kind of let's say 2021.
Yes, that's a great question I think on a previous call. We said that we can see a pathway potentially to 650 foot and.
Thats still probably a pretty good target.
We certainly have plenty of efficiency initiatives still underway and some other ideas. So.
Potentially go lower than that but right now six fiftys may begin 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 Amir.
There is not it does not include the $51 million from the override.
Sale that's not included.
No the the.
The judgment the lawsuit judgment is not included we're just modeling that into next year.
For conservatism, so now it says something else.
Okay, great. Thank you guys.
Thank you.
Thank you Sir our next question comes from Gregg Brody with Bank of America. Please proceed with your question.
Good morning, guys.
Hi, Greg good morning.
Just following up on the free cash flow question.
Does that does that number includes the payment to for the ROI for the overriding royalty interest.
It does not include the override the 51 million dollar override.
Payment no.
No I mean, the your your royalty that.
It is that Oh, yes, absolutely that yes, when we when we talk about free cash flow numbers is certainly a net free cash flow thats right.
Thats going to be coming through.
The cash flow statement going forward as a finance activity correct.
That's right. It's a it's a one line item in the cash flow statement.
How much should we think about that being.
This year.
Second quarter was $3 million.
Going forward for for the second half its around $30 million to $35 million.
Got it so thats in that 20 million to that of that.
You are correct.
You mentioned the dilutive.
The double Gn litigation, you're expecting that to push out the 21 now.
Yes.
Yes, I think the.
The whole cold shutdown has not been friendly to that that 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.
And then you as you would just activity do you expect.
That's a significant accrued capex repayment.
That actually came in the second quarter, we had about a 90 million dollar investment in working capital. This quarter. So you saw the big jump.
As mentioned in the second quarter, you went from 300 320 million up DNC capital down the 180 from the first second quarter. So that really occurred in May and June.
Got it so that makes that makes sense I saw the big jumps.
Yes, that's a onetime or that's behind US now probably goes the other way a little bit going forward.
Got it.
It's just maybe just talking about you mentioned all the asset sales opportunities.
Confident asset sales.
Yes, the year.
Is there is there anything that's a leading Kevin that those two we should be thinking about.
No I think we're looking at items really across those four columns on the on the page, where we outline asset sales so.
It's all about optimizing in these things take time and Thats why we gave ourselves that the year to complete.
Neither be volatility, we never anticipated to 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 we'll get the rest of that this year.
Great.
That's that's it from me I'll jump back into queue.
Thanks, guys. Thanks, Rick.
Thank you.
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.
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