Q2 2019 Earnings Call
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 Anteros second quarter 2019, Investor Conference call.
Well spend a few minutes going through the financial and operational highlights and then we'll open it up for Q and a.
I would also like to 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 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 anteros 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 Glen 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 focused on our recently announced well cost and operating cost savings initiatives.
I will provide detail on savings we've achieved to date and highlight the key items that will reduce costs further towards our target.
Glen will then highlight our second quarter financial achievements, including the premium NGL price realizations. Following our first full quarter with Mariner East two 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 prices 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 calm flexed Ken context, if we elect to just maintain year end 2021 forecast production.
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 down shifting to maintenance 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 costs.
Reductions.
Please note that all these numbers assume a lateral length of 12000 feet.
We are targeting a reduction in well costs of 10% to 14% on a per lateral foot basis, or approximately $1.2 million 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 cost of 0.9 $7 million per thousand feet.
To a target of 0.8 $3 million to 0.8 $7 million per thousand 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 0.9 $7 million per thousand feet.
That was assumed in our budget.
During the first half of the year, we've already achieved savings of approximately $500000 per well, which brings us to our current a fee.
With second half 2019, well costs estimated at.
The 0.9 $3 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 a fee of 0.9 $3 million per thousand feet of lateral we expect well costs to decline further to the range of 0.83 to 0.8 $7 million per thousand feet by Cal 20.
These additional savings are expected to come primarily from our water savings initiatives, both on enhanced flowback 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 break down.
You can see the breakdown by category, assuming the midpoint of our targeted well cost reductions of $1.2 million to $1.7 million.
We are targeting approximately $800000 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, repurchasing portions of our existing freshwater system to transport the water and three constructing additional water pipeline infrastructure.
Historically, we've used through third party trucking companies to transport, our flowback and produced water at a cost of between six and $9 per barrel.
Over the last 12 months, we have paid nearly a $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 test and analyze the optimal completion design to maximize returns.
After successful pilots using mostly 100 mesh proppant.
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 proppant in the most cost a cost effective manner.
We have not seen any evidence of degradation.
In either production or are you ours 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.
And often overlooked by product 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 to 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 with a meaningful reduction in total vendor costs.
Further savings will come from last mile San 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 5400 70.
Feet of lateral drilled per day.
Approximately one mile little over a mile every single day, 20% improvement from our Twond 2018 average.
In addition, we achieved what we believe is a world record again by drilling a total of 9600 50 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 16279 feet sideways.
These efficiency gains combined with service cost deflation.
Our expected to reduce well costs by approximately $650000 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 LLC.
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 flowback water.
And the cost to track 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 low eight.
So let me talk a little bit more about Alloa lease operating expenses in the first half of 2019.
Produced water costs represented approximately 80% of total allo we.
Assuming antero midstream provides the new expanded produced water services, we expect our OE 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 peer Marcellus well cost comparison.
Provides a snapshot of our Appalachian peer well costs and future targets.
Keep in mind that there is a variance among producers as to what costs are captured in capitalize well costs versus LLC, 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 still 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 DMC capex run rate approximately at 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 cost 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 billion to $1.3 billion in Cal 20.
The decline in capital spend during Cal 20 is despite a similar a similar number of well completions.
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 Mariner East two pipeline in service, giving us access to premium priced global LPG prices are markets. We hold about one third of the current 165000 barrels a day of capacity on Mariner East two making us the largest shipper on this pipeline during the quarter, we realized an unhedged average C plus NGL price of $28.57 per barrel for the quarter, that's $1.68 per barrel premium to Mont Belvieu pricing.
As shown in slide number seven title inflection point in NGL marketing and pricing, 55% of C. Plus volumes were exported and realized a 19 cents per gallon premium to Mount Bellevue pricing in the table on the right hand side of the slide we provide guidance on NGL realizations relative to Mont Belvieu pricing for the full year 2019, as you can see on a blended basis essentially flat to Bellevue to slightly.
Positive premium of four cents per gallon now, let's take a look at the impact of that Amy too has had on northeast NGL differentials since the in service of immune to in February of this year.
Anteros NGL price differentials improved by over $6 per barrel flipping from a discount to a premium to Mont Belvieu. 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 165000 barrel a day falling on a me too evacuates almost 40% of the basins 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 MB two Emmy too is that dotted.
Vertical line over to the right first half 2018 realizations averaged approximate $5.75 per barrel discount to Mont Belvieu.
Despite the softer domestic prices seen during the first half of 2019 versus the prior year, our realized price relative to Mont belvieu improved by over $6 per barrel and flip to a premium to the index.
In addition, and also not depicted on this chart our in Basin C plus NGL price realizations have also improved following the startup of MB two.
C 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 2018.
Looking forward to 2020 with the completion of the full Emmy to project expected by the end of 2019 total pipeline capacity will increase to 275000 barrels a day on Emmy too.
At that time.
We have the option to increase our capacity by as much as 50000 barrels a day and 10000 barrels a day increments that would take us up to 100000 barrel a day of firm capacity, which would increase our exposure to international pricing to the 65% to 75% range on anteros expected NGL production in the year 2020.
This expansion would also evacuated a higher percentage of regional supply, which is expected to further boost in basin price differentials.
Our significant volumes on any to 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 have missed it we have been publishing a new presentation on our website titled Weekly International LPG pricing update on the home page.
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 your prices are the eight cents and 14 cents per gallon premium respectively to Mont Belvieu net of shipping.
I'd like to touch on the NGL macro briefly the current weak NGL pricing in Mont Belvieu is due to limited export capacity along the Gulf coast, Although we expect soft price it to persist through the third quarter, we do see Mont belvieu 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 Mont belvieu NGL pricing.
In the northeast the in service of full capacity on Mariner East two will provide increased exports through the Marcus Hook 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 entitled Pure 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 and may be too.
Assuming approximate 10% annual production gross growth this 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 use producer that is 100% hedged on expected natural gas production in 2019 as shown on slide number 11 and 12.
And have significantly more hedge protection in 2020 and 2021 in 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 our countries 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 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 return 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 in 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 million 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 billion 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 dollar 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 in 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 Bcf a day to be approximately $670 million.
In summary, please turn to slide number 15 title Asrs 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 provide substantial adequate liquidity and affords us production 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 ill now turn the call over the operator for questions.
Thank you.
We will now be conducting our question and answer session.
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Our first question comes from Welles Fitzpatrick with Suntrust. Please state your question.
Hi, good morning.
Good morning.
There's certainly a chance that 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 end of the day, you're much better off completely pass in the same general area from a from operating and capital cost standpoint. So right now were really mastered develop in the.
Very much liquids rich Marcellus, but we'd like to Utica as well and we just brought on six.
Dry gas wells, which probably alluding to in the quarter and those look really strong.
NGL 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.
As we jump from.
Completions at 12, 40 beat you to the 12 75 beats, you and back and forth. So thats just kind of area those are pretty chunky, obviously, when you're bringing on 810 12, well pads. So it can impact the quarterly numbers, though.
Okay. Okay, perfect and then just one last one for me.
The previous multi year guidance I think that it had something of a 10% to 15% sort of self guided for growth, but obviously at a much higher commodity price should we think you know how should we be thinking of that going forward, obviously prices are lower but you're doing a lot to offset that because of the costs.
How should we refrain that moving forward.
Yes, I think you can see from all materials in 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 we're not looking at that upside growth case and in fact, if we see improvement in commodity prices, which we certainly think we will over the coming quarters and years.
That was to be captured as additional cash flow for for deleveraging and other uses not for accelerating the capital plan.
Makes sense. Thanks, thanks, so much for your time.
Thank you. Thank you.
Our next question comes from Jane shots on goal with Stifel. Please state your question.
[noise], but mining I have an easy question just start with maybe you can discuss the capex and production cadence over the remainder of 2019.
No no no I'm I'm talking about Capex and production cadence how should we think about the case you know quite how about what our production for Threeq and Fourq, you and also a capex spending.
On the call, we expect that to run in that $300 million, maybe a little bit over $300 million each quarter.
The next many quarters really.
Okay. So I suppose it would it fair to say that that capex spending all by that they mean, though the yeah would be BT spread out like equally spread out over the remaining two quarters, yeah, exactly like that that message change pretty pretty flat.
Okay. Okay, and then you know given a very strong in Twoq paradox and I'm. Just curious if that was expected you know given the.
Well cadence.
On U.S. side that you know given given the very strong QQ production, how should be think about full year production guidance are you expecting now it took I mean on the high end over the full year production guidance midrange or maybe low and.
Hi, I think 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 well so I think you're seeing some of that but.
No we're not 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 getting season to see.
We always look at that but.
So far there is you know its a.
It's difficult in this environment as prices have contracted the spreads have contracted to so the ft is less desirable.
Okay. Thank you so much.
Thank you.
Our next question comes from Holly Stewart with Scotia, Howard Weil. Please state your question.
Good morning, gentlemen.
Good morning.
Or that percentage it was at 80% eight zero percent okay Hello.
Big number and then it 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 off 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 fracstem or or the Fracs go further out away from the Wellbore.
Depending on how much water you use and.
The converse is with sand, it's better near Wellbore conductivity, as we say the fractures are well connected.
So we saw that we didnt need to go quite as wide and half lengths between wellbores that.
We could cut back on the water.
What we see of course, the industry and so we we are seeing things just the way. The industry is at 100 mesh is a little bit simpler we use some of the.
Course or matches in some of our designs that 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.
10, or 15% cut on the water and stick with mostly hundred mesh on the proppant and.
Thats working well.
And do you have an estimate of how much of that specifically is helping in terms of well cost.
We have a.
I want to there, let's see mikes filling out his number $280000 per well just on the water and then the actual produced water savings because you have lower produced water because you now have less water and as a further 108. So it's about $400000 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 our part of the well cost. So thats the 280 and then the.
Next amount that Mike talked about is the Ela, we savings beyond the first 90 days, but it's material for both.
Definitely an important.
Cash factor for Us yes.
That's very helpful.
Maybe this is one for you Glenn I know you talked in detail in the release about.
About utilizing the lower cost ft as opposed to the higher cost projects. So can you 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.
Yes, the other day I think our molecules are just chasing the best pricing the best Netbacks and when you have tight differentials in the basin and.
Youre, keeping some of the gas closer to home and that's what we've seen some in the in the second quarter I think it's.
As simple as that okay. Okay. That's helpful.
And then maybe finally for me just on a high level, just kind of thoughts around the am ownership here I know historically these you sort of use that to raise you know to raise capital at least each year, maybe with the exception of 2018, but there's 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 $200 million or so of dividend stream and simply growing over time so.
It'd be tough to sell it particularly today it at a 13% kind of yield so.
Tough wrestle like all of it is what I'm getting at so.
We're not inclined to do anything with it today, and we really enjoy that ownership and see.
Tremendous amount of upside in a so.
I think we will stand path for now.
Okay.
Perfect. Thanks, guys.
Thanks, Howard Thank you.
Our next question comes from Brian singer with Goldman Sachs Goldman Sachs. Please take your questions.
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.
Yes of course, we've got great rates on those those two bonds that you're alluding to.
And they are they come due at the end of each of those years. So we've got almost two and a half years on the on the 2021 maturity and obviously 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 tougher on the last month or so and so we'll be opportunistic about that but.
I think thats not something that keeps us up at night by any means we've got 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.
All in good shape as far as we're concerned.
Great. Thanks, and then just a couple of follow ups to the points made earlier, the $1.2 billion to $1.3 billion exploration and development budget, what production growth do you expect that.
But to get given 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.
Yes on the on the production I mean, we talk about a 10% production CAGR and that's a multiyear look so I think.
You can handicap that give or take two or 3% either side of that but thats kind of the outlook for the next few years. So I think you'll see us sort of average.
10% production growth and that that 1.2 to 1.3 billion next year keeps us.
And then similar levels and 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 in that range. So so we feel good about that.
And then on the litigation.
On the litigation front, yes those.
We wouldn't talk about those publicly if they were pretty far down the road and so.
There was a jury trial on the biggest piece of that with a.
Utility with WGCL 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 thats a good handicapping in the year 2020.
The other great thanks sounds or other ones at South Jersey, Brian you can read about that in the.
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 Subash Chandra with Guggenheim Partners. Please state your question.
Yes, Hi, Mike what a vocabulary is also challenged so.
Just wanted to ask for some clarification my understanding at least is that Theres a few pathways.
In the in the water business.
One is the disposal cleaning it up to Clearwater and putting it into.
I guess.
Your buy water bodies et cetera.
The other is recycling and there might be other aspects of it but.
Could you kind of clarify.
Where the savings are occurring.
First of all and second of all.
What remaining aspects of the water handling.
Our future challenges.
And then.
Then finally is the water stuff discussed.
On the print today.
Is it 100% application or are you easing into it in 2020.
Good question. So my first question, Yes, I think that's a good tutorial on what's what's going on so.
I mean, I'll turn 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 as we move north in the liquids rich area. I mean, some of that is 20 530 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 $678, a barrel, where essentially reusing it right. There in the area. So thats why we refer to it as local.
Reuse and it goes goes right back into the next to completion, so just shortening the loop and taking the trucking out and the fees are also.
Presume to be a bit lower for the cleanup of the water we're doing locally.
Yes, that's where I think the fees can be lower because the cleanup we can take advantage of blending as well by just taking the effluent just as Clearwater does but.
Not doing as deep as Scott and.
The flowback and produced water.
And and blending it down and using it in.
Future completions so.
As Glenn said big savings on the trucking side, because we're keeping a close to where the development is and then big savings on the clean up in that we can use polishing and blending down too.
Be a little more economic.
And then in terms of what we're talking about we we'd be completing wells in the liquids rich fairway Woods call. It 70, 525 freshwater and then.
This clean water up locally and that will vary over time. It can be 80 20, it's just going to it's going to vary a bit but we are blending and some water. This treated locally is the is the whole concept of we'll be doing some of that this year and I think as far as you ask about proportionally.
Yes, 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 and this focus development area to the north and so.
We will be doing both polishing and blending there and.
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, these water savings apply to all these wells.
If possible yes.
Yes, we've got our logistics team working to two.
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 weekend.
Use that water right next door to complete the next band so a nice focus that way and so so yes.
The the goal will be to do it on a 110 to 120 wells next year.
And apply those savings not only the well cost savings, but the OE savings through that throughout the board.
Okay, I'll, let that sink and I'll, probably follow up offline over next couple of weeks.
Just another follow up on.
The simultaneous operations is that.
Yes on the larger pads is that pretty common right now is that built into the 2020 guidance.
You know, it's a we've done it we've done it recently the same ops where were.
Having either two crews at once on different ends of the pad and we're completing or we're drilling on wind down and completing on the either but I think we have enough flexibility that we don't.
We don't have to do that all that often and.
There is not much gap in cycle time so.
So were built to do that but we it's probably about 15% of our pads that we do sign maps.
Okay. Thank you thanks guys.
Yes.
Our next question comes from Sean Sneeden with Guggenheim Securities. Please ask your question.
Hi, Thanks for taking the questions.
Sure. Thanks.
Glenn.
Maybe for you just on leverage.
Ticked up a little bit in the quarter.
When you think about trying to maintain it was been typically pretty conservative balance sheet.
It sounds like.
In the near term kind of comfortable with the level of liquidity liquidity and funding the outspend that way.
But when you think about different levers that you may have to address keep leverage in check near term I guess, how are you guys thinking about.
Some of the non core stuff you may have whether its Utica we're have you.
You know am units or or slowing down.
Yes, yes, the slowdown thats not really in the cards I mean thats. What this is all about writing and proving capital efficiencies and reducing well cost and enables us to continue on that on the pace that we've been talking about so thats really not something thats being.
Kicked around in terms of.
Cash flow free cash flow needs the outspend.
It's in the <unk> over the next three four years, it's in the several hundred million dollars Nada using stays true 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.
EBITDA is come down a bit for everyone over the past few quarters.
With the commodity price coming down so it's really the.
You know the denominator that's come down a bit so we're managing the balance sheet, just fine, it's not not growing tremendously and.
We're very comfortable with where we are and you'll see us continue to hedge optimistically as well.
Got as far as I'm, sorry that you mentioned divestitures or whatever.
The door is 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.
It gives us you know sort of unparalleled inventory in the in the basin.
Yes, the doors open for those kinds of things. So I don't think they are big needle movers, but could happen.
Understood that's helpful.
And then just on on.
Theme can you remind us what your your ft minimums are there and I guess fair to assume that just that.
Current prices and strip.
Jack above those levels.
Yeah, we are.
We're recovering.
40, 41000 barrels a day and.
Much of that is fair from sales our ft.
We have 20000 barrels a day on Atex for ethane transport to Mount Bellevue.
We've laid some of that off so net to antero 10000 barrels a day, which we are using to facilitate from sales here and there, but we have a number of firm sales too.
To different parties, both internationally and also domestically internationally, including Sarnia so.
So.
Where we're a little above.
Our firm sales are a little bit higher than our must recover but we always have an eye on.
BT you have the residue stream coming out of the plants and we.
We certainly have flexibility to recover more but right now as you know the numbers say reject the ethane where you can accept.
Again to stay within.
Spec and also to fulfill some firm from sales on ethane.
Got it that makes sense.
And.
Can you remind us what's the average tenure of the firm sales arrangements.
I would say the amount.
Yes, 10 to 20 years I would say.
We're a.
Based provider for the upcoming shell Cracker, just west of Pittsburgh, So that will be even more supply and that is.
20 year contract, there and some of our journey.
Oh excuse me 15.
But we have international with.
Contracts with borealis with any dose with others that are typically 10 year contracts.
Perfect I appreciate the color guys. Thanks.
Okay. 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, so just $275 million outspend.
Excluding onetime 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 miss that but.
We we want to fill our transport and we still have economic drilling to do and so we're saying that 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 and the beauty of what the assumption or any other assumptions year over year and any other color I guess that you can provide.
No I can't think of any.
Okay, and then moving on to my last question I was just wondering if you could provide free cash flow sensitivity to say, a dollar change and C plus NGL pricing given.
Your mention of 29 dollar.
Assumption be it helps your pricing for next year.
[noise] Yeah looking at you know we produced about 100000 barrels a day so thats.
365 36.5.
A million barrels to one dollar to 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.
Gentlemen, last December you unloaded some of the 2019 gas hedges and it looks like a rare Miss on your hedging strategy are you bullish on gasoline on 2020.
On decline rates and what's your timing just off work the new longer dated to.
Hedges that you put on in the second quarter.
Give us a more pessimistic view on go forward pricing.
Well you know to be in this business what has to be optimistic. So you know we we are positive thinkers and optimistic but we're also defensive so the hedges that we added were definitely.
If it.
Not only a price target, but it's when does it happen and so just to be protecting the balance sheet, we added hedges through count 20.
You're right. It's you know as we monetize some hedges you know always have an eye on.
Uh huh.
On de levering and putting.
Putting out there putting forward the best credit metrics, a we were seeing a positive set up in terms of supply and demand. When we did that back in December but yes in hindsight that was a miss you know we would have been better off to just hold on to those we wouldn't have paid down 350 million of debt or so, but we would have.
We mark that to market every month or so just to learn and.
And from our decisions and that was one where we would have been maybe a $100 million ahead by not doing that.
Yes, I think it's really demand has been soft little bit softer than expected, it's not really been the supply Oh and then just the overall sentiment so that kind of caught us off sides I guess.
Okay and then in terms of the strategy you guys have laid out some 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 T are there any other strategic moves available to you like selling a acreage central midstream asset JV sales that might help arrest some of the capital declines and preserve capital here.
Well, it's all they happen I mean keep in mind were 2.3 times Levered and we have well over $1 billion of liquidity. So I mean, there is not a real a sense of urgency to do those kinds of more dramatic things and.
Sure, we're always looking to strategic things a lot of which we can't really talk about publicly until they're done but.
We're always working in lots of different alternatives.
Okay excellent.
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.